Robust Integrated Process for Conversion of Waste Plastics to Final Petrochemical Products

ABSTRACT

A robust integrated process for the conversion of waste plastics to high value products. The robust integrated process allows for operation with a single hydroprocessing reactor which provides simultaneous hydrogenation, dechlorination, and hydrocracking of components of a hydrocarbon stream to specifications which meet steam cracker requirements, with the option to further dechlorinate the treated hydrocarbon stream in a polishing zone.

CROSS REFERENCE TO RELATED APPLICATIONS

The present application is a continuation of and claims priority toInternational Application No. PCT/IB2016/051137 filed Mar. 1, 2016,entitled “A Robust Integrated Process for Conversion of Waste Plasticsto Final Petrochemical Products,” which claims priority to U.S.Provisional Application No. 62/201,676 filed on Aug. 6, 2015, entitled“A Robust Integrated Process for Conversion of Waste Plastics to FinalPetrochemical Products,” and Indian Provisional Application No.1171/CHE/2015 filed Mar. 10, 2015 entitled “A Robust Integrated Processfor Conversion of Waste Plastics to Final Petrochemical Products,” whichapplications are incorporated by reference herein in their entirety.

TECHNICAL FIELD

The present disclosure relates to the treatment of hydrocarbon streamsresulting from pyrolysis of waste plastics for use in downstreamprocesses.

BACKGROUND

Waste plastics contain polyvinylchloride (PVC). Through a pyrolysisprocess, waste plastics can be converted to gas and liquid products.These liquid products contain paraffins, i-paraffins (iso-paraffins),olefins, naphthenes, and aromatic components along with organicchlorides in concentrations of hundreds of ppm. As such, the liquidproducts of a pyrolysis process (pyrolysis oils) can be used as afeedstock for steam crackers partly replacing naphtha used in theseunits. However, pyrolysis oils do not meet the steam cracker feedspecification requirements of chloride levels less than 3 ppm, olefincontent less than 1 wt %, and boiling end point requirements of 370° C.

SUMMARY

Disclosed herein is a process for converting waste plastics to a highvalue product comprising converting the waste plastics to a hydrocarbonstream in a liquid phase, wherein the hydrocarbon stream comprises oneor more chloride compounds in a concentration of 5 ppm or more based ona total weight of the hydrocarbon stream, contacting the hydrocarbonstream with a first hydroprocessing catalyst in the presence of hydrogento yield a first hydrocarbon product comprising C₁ to C₄ gases and C₅+liquid hydrocarbons, recovering the C₅+ liquid hydrocarbons in a treatedhydrocarbon stream from the first hydrocarbon product, wherein thetreated hydrocarbon stream comprises the one or more chloride compoundsin a concentration of 3 to 5 ppm based on a total weight of the treatedhydrocarbon stream, dechlorinating the treated hydrocarbon stream toyield a polished hydrocarbon stream comprising one or more chloridecompounds in a concentration of less than 3 ppm based on a total weightof the polished hydrocarbon stream, and feeding the treated hydrocarbonstream or polished hydrocarbon stream to a steam cracker to yield thehigh value product, wherein the treated hydrocarbon stream or polishedhydrocarbon stream meets steam cracker feed requirements for chloridecontent, olefin content, and boiling end point.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a hydroprocessing system for converting plastic wasteto a high value product by simultaneously dechlorinating chloridecompounds, hydrogenating olefins, and hydrocracking heavy hydrocarbonmolecules contained in a hydrocarbon stream which contains a pyrolysisoil to levels suitable for introduction to a steam cracker.

FIG. 2 illustrates an embodiment of a polishing zone in thehydroprocessing system.

FIG. 3 is a graph of the boiling point distribution for a liquid productof a low severity pyrolysis process, showing temperature versus masspercent.

FIG. 4 is a graph of a staged catalyst sulphiding protocol, showingtemperature versus time.

DETAILED DESCRIPTION

Other than in the operating examples or where otherwise indicated, allnumbers or expressions referring to quantities of ingredients, reactionconditions, and the like, used in the specification and claims are to beunderstood as modified in all instances by the term “about.” Variousnumerical ranges are disclosed herein. Because these ranges arecontinuous, they include every value between the minimum and maximumvalues. The endpoints of all ranges reciting the same characteristic orcomponent are independently combinable and inclusive of the recitedendpoint. Unless expressly indicated otherwise, the various numericalranges specified in this application are approximations. The endpointsof all ranges directed to the same component or property are inclusiveof the endpoint and independently combinable. The term “X or more” meansthat the named component is present in an amount of the value X, andvalues which are more than X.

The terms “a,” “an,” and “the” do not denote a limitation of quantity,but rather denote the presence of at least one of the referenced item.As used herein the singular forms “a,” “an,” and “the” include pluralreferents.

As used herein, “combinations thereof” is inclusive of one or more ofthe recited elements, optionally together with a like element notrecited, e.g., inclusive of a combination of one or more of the namedcomponents, optionally with one or more other components notspecifically named that have essentially the same function. As usedherein, the term “combination” is inclusive of blends, mixtures, alloys,reaction products, and the like.

Reference throughout the specification to “an embodiment,”“embodiments,” “another embodiment,” “other embodiments,” “alternativeembodiments,” “additional embodiments,” “some embodiments,” and so forth(e.g., the use of “additionally” and/or “alternatively” in the contextof describing one or more embodiments), means that a particular element(e.g., feature, structure, property, and/or characteristic) described inconnection with the embodiment is included in at least an embodimentdescribed herein, and may or may not be present in other embodiments. Inaddition, it is to be understood that the described element(s) can becombined in any suitable manner in the various embodiments.

Disclosed herein are embodiments of a process for converting wasteplastics to a high value product. Embodiments of the process includeconverting the waste plastics to a hydrocarbon stream in a liquid phase,converting the waste plastics to a pyrolysis light gas stream containingC₁ to C₄ hydrocarbons, contacting the hydrocarbon stream with ahydroprocessing catalyst in the presence of hydrogen (H₂) to yield ahydrocarbon product, recovering a treated hydrocarbon stream comprisingC5+ hydrocarbons from the hydrocarbon product, dechlorinating thetreated hydrocarbon stream to yield a polished hydrocarbon stream,recovering a hydroprocessed light gas stream from the hydrocarbonproduct, feeding the treated hydrocarbon stream to a steam cracker toyield the high value product, feeding the polished hydrocarbon stream toa steam cracker to yield the high value product, feeding the pyrolysislight gas stream to the steam cracker, feeding the hydroprocessed lightgas stream to the steam cracker, or combinations thereof. The treatedhydrocarbon stream or polished hydrocarbon stream meets steam crackerfeed requirements. The pyrolysis light gas stream may be fed to thesteam cracker directly, or after treating the pyrolysis light gas streamin a scrubbing unit to yield a treated pyrolysis light gas stream whichis subsequently fed to the steam cracker. The hydroprocessed light gasstream may be fed to the steam cracker directly, or after treating thehydroprocessed light gas stream in a scrubbing unit to yield a treatedhydroprocessed light gas stream which is subsequently fed to the steamcracker. Converting the waste plastics to a hydrocarbon stream in aliquid phase and converting the waste plastics to a pyrolysis light gasstream containing C₁ to C₄ hydrocarbons may occur simultaneously viapyrolysis of the waste plastics.

Embodiments of the process are described in more detail with referenceto FIG. 1. FIG. 1 illustrates a hydroprocessing system 100 forconverting plastic waste to a high value product by simultaneouslydechlorinating chloride compounds, hydrogenating olefins, andhydrocracking heavy hydrocarbon molecules contained in a hydrocarbonstream 12 which contains a pyrolysis oil (e.g., plastic pyrolysis oil,tire pyrolysis oil) to levels suitable for introduction to a steamcracker 50. The system 100 includes a pyrolysis unit 10, ahydroprocessing reactor 20, a separator 30, a polishing zone 40, and asteam cracker 50. Waste plastic is either placed in the pyrolysis unit10 or fed to the pyrolysis unit 10 via waste plastic stream 1. In thepyrolysis unit 10, the plastic waste stream is converted via pyrolysisreactions to pyrolysis gases (e.g., C₁ to C₄ gases) and a liquidpyrolysis oil. The pyrolysis gases flow from the pyrolysis unit 10 via apyrolysis light gas stream 16 directly to the steam cracker 50, or to ascrubbing unit 60 and then the steam cracker 50. The liquid pyrolysisoil flows from the pyrolysis unit 10 via hydrocarbon stream 12. Thehydrocarbon stream 12 feeds to the hydroprocessing reactor 20, and thereaction product effluent of the hydroprocessing reactor 20 flows fromthe hydroprocessing reactor 20 in the hydrocarbon product stream 22 tothe separator 30. In separator 30, a treated product (e.g., in gas orliquid form) is recovered from the hydrocarbon product stream 22 andflows from the separator 30 via treated hydrocarbon stream 32, with oneor more of sulphur-containing gases and chlorine-containing gasesflowing from the separator 30 in hydroprocessed light gas stream 36. C₁to C₄ hydrocarbon gases which are generated in the hydroprocessingreactor 20 may flow directly to a separator 30, where the C₁ to C₄hydrocarbon gases are recovered in a hydroprocessed light gas stream 36for flow directly to the steam cracker 40, to a scrubbing unit 50, or acombination of direct flow to the steam cracker 40 and flow to thescrubbing unit 50 (e.g., a portion of the pyrolysis light gas streambypasses the scrubbing unit).

In embodiments where the chloride content of the treated hydrocarbonproduct meets steam cracker requirements, the treated hydrocarbonproduct in the treated hydrocarbon stream 32 may flow directly (e.g.,without any separations or fractionations of the treated hydrocarbonstream 32) via bypass stream 34 to a steam cracker 50, from which highvalue products flow in stream 52. In embodiments where the chloridecontent of the treated hydrocarbon product does not meet steam crackerfeed requirements, the treated hydrocarbon product may flow in thetreated hydrocarbon stream 32 to polishing zone 40, where furtherdechlorination occurs to yield the polished hydrocarbon stream 42. Thepolished hydrocarbon stream 42 may then flow directly (e.g., without anyseparations or fractionations of the polished hydrocarbon stream 42) tothe stream cracker 50, from which the high value products flow in stream52.

Waste plastics which are loaded into or fed to the pyrolysis unit 10 viawaste plastic stream 1 may include post-consumer waste plastics.Examples of waste plastics which can be used include chlorinatedplastics (e.g., chlorinated polyethylene), polyvinylchloride,non-chlorinated plastics (e.g., polyethylene, polystyrene,polypropylene, copolymers, etc.), or mixtures thereof. Waste plastics asdisclosed herein also include used tires.

Waste plastics in the pyrolysis unit 10 are subjected to a pyrolysisprocess to convert the waste plastics to one or more pyrolysis oilswhich flow from the pyrolysis unit 10 via hydrocarbon stream 12. Thepyrolysis processes in the pyrolysis unit 10 may be low severity or highseverity. Low severity pyrolysis processes may occur at a temperature of250° C. to 450° C., may produce pyrolysis oils rich in mono- anddiolefins as well as a significant amount of aromatics, and may includechloride compounds in amounts which cause the hydrocarbon stream 12 tohave the chloride compound concentrations disclosed herein. Highseverity pyrolysis processes may occur at a temperature of 450° C. to750° C. and may produce pyrolysis oils rich in aromatics. The liquidproduct of the high severity processes may include chloride compoundswhich cause the hydrocarbon stream 12 to have the chloride compoundconcentrations disclosed herein.

In embodiments, the pyrolysis unit 10 may be one or more vesselsconfigured to convert waste plastics into gas phase and liquid phaseproducts (e.g., simultaneously). The one or more vessels may contain oneor more beds of inert material or pyrolysis catalyst comprising sand,zeolite, or combinations thereof. Generally, the pyrolysis catalyst iscapable of transferring heat to the components subject to the pyrolysisprocess in the pyrolysis unit 10. In an embodiment where the pyrolysisunit 10 is two vessels, the pyrolysis process may be divided into afirst stage which is performed in the first vessel and in a second stagefluidly connected downstream of the first stage which is performed inthe second vessel. The first stage may utilize thermal cracking of thewaste plastics, and the second stage may utilize catalytic cracking ofthe waste plastics to yield the hydrocarbon stream 12 flowing from thesecond stage. Alternatively, the first stage may utilize catalyticcracking of the waste plastics, and the second stage may utilize thermalcracking of the waste plastics to yield the hydrocarbon stream 12flowing from the second stage.

In additional or other embodiments, the pyrolysis unit 10 may includeone or more equipment configured to convert waste plastics into gasphase and liquid phase products. The one or more equipment may or maynot contain any inert material or pyrolysis catalyst as described above.Examples of such equipment include one or more of heated extruders,heated rotating kiln, heated tank-type reactors, empty heated vessels,enclosed heated surfaces where plastic flows down along the wall andcracks, vessels surrounded by ovens or furnaces or other equipmentoffering a heated surface to assist in cracking.

In one or more embodiments of the pyrolysis unit 10, a head space purgegas is utilized in all or a portion of the pyrolysis stage(s)(conversion of waste plastics to a liquid phase and/or gas phaseproducts) to enhance cracking of plastics, produce valuable products,provide a feed for steam cracking, or combinations thereof. The headspace purge gas may include can utilize hydrogen (H₂), nitrogen (N₂),steam, product gases, or combinations thereof. The use of a head spacepurge gas assists in the dechlorination in the pyrolysis unit 10. Theuse of hydrogen in the pyrolysis unit 10 has beneficial effects of i)reducing the coke lay down as a result of cracking, ii) keeps catalystused (if any) in the process in an active condition, iii) improvesremoval of chloride from stream 1 such that the hydrocarbon stream 12from pyrolysis unit 10 is substantially dechlorinated with respect towaste plastic stream 1 which minimizes the chloride removal requirementin hydroprocessing reactor 20, iv) reduces diolefins in hydrocarbonstream 12, v) helps operate the pyrolysis unit 10 at reducedtemperatures for same levels of conversion of waste plastic stream 1 inthe pyrolysis unit 10, or combinations of i)-v).

An example of a pyrolysis process for waste plastics is disclosed inU.S. Pat. No. 8,895,790, which is incorporated by reference in itsentirety. Another example of a pyrolysis process is disclosed in U.S.Provisional Patent Application No. 62/025,762, titled “UpgradingHydrogen Deficient Streams Using Hydrogen Donor Streams in aHydropyrolysis Process,” filed Jul. 17, 2014, which is incorporated byreference in its entirety.

The hydrocarbon stream 12 generally includes one or more pyrolysis oils(e.g., plastic pyrolysis oil, tire pyrolysis oil). In embodiments, thehydrocarbon stream 12 may include one or more pyrolysis oils asdescribed above which is blended with a heavier oil (e.g., a naphtha ordiesel, via spiking stream 14).

In an embodiment wherein the hydrocarbon stream 12 does not contain theone or more sulphides in the concentrations disclosed herein, thehydrocarbon stream 12 may be spiked with the one or more sulphides, viaa spiking stream 14 (discussed in more detail below).

Examples of the components which may be included in the hydrocarbonstream 12 include paraffins (n-paraffin, i-paraffin, or both), olefins,naphthenes, aromatic hydrocarbons, or combinations thereof. When the oneor more hydrocarbons includes all the listed hydrocarbons, the group ofhydrocarbons may be collectively referred to as a PONA feed (paraffin,olefin, naphthene, aromatics) or PIONA feed (n-paraffin, paraffin,olefin, naphthene, aromatics).

Any paraffin may be included in the hydrocarbon stream 12. Examples ofparaffins which may be included in the hydrocarbon stream 12 include,but are not limited to, C₁ to C₂₂ n-paraffins and i-paraffins. In anembodiment, the concentration of paraffins in the hydrocarbon stream 12may be less than 10 wt % based on the total weight of the hydrocarbonstream 12. Alternatively, the concentration of paraffins in thehydrocarbon stream 12 may be 10 wt %, 20 wt %, 30 wt %, 40 wt %, 50 wt%, 60 wt %, or more based on the total weight of the hydrocarbon stream12. While embodiments include paraffins of carbon numbers up to 22, thedisclosure is not limited to carbon number 22 as an upper end-point ofthe suitable range of paraffins, and the paraffins can include highercarbon numbers, e.g., 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33,34, 35, 36, 37, 38, 39, 40, and higher. In embodiments, at least aportion of the paraffins in the hydrocarbon stream 12 comprises at leasta portion of the heavy hydrocarbon molecules.

Any olefin may be included in the hydrocarbon stream 12. Examples ofolefins which may be included in hydrocarbon stream 12 include, but arenot limited to, C₂ to C₁₀ olefins and combinations thereof. In anembodiment, the concentration of olefins in the hydrocarbon stream 12may be less than 10 wt % based on the total weight of the hydrocarbonstream 12. Alternatively, the concentration of olefins in thehydrocarbon stream 12 may be 10 wt %, 20 wt %, 30 wt %, 40 wt % or morebased on the total weight of the hydrocarbon stream 12. In embodiments,at least a portion of the one or more olefins in the hydrocarbon stream12 comprise at least a portion of the heavy hydrocarbon molecules.Alternatively, none of the heavy hydrocarbon molecules in thehydrocarbon stream 12 are olefins. While embodiments include olefins ofcarbon numbers up to 10, the disclosure is not limited to carbon number10 as an upper end-point of the suitable range of olefins, and theolefins can include higher carbon numbers, e.g., 11, 12, 13, 14, 15, 16,17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, and higher.

In an embodiment, the hydrocarbon stream 12 comprises no olefins.

Any naphthene may be included in the hydrocarbon stream 12. Examples ofnaphthenes include, but are not limited to, cyclopentane, cyclohexane,cycloheptane, and cyclooctane. In an embodiment, the concentration ofnaphthenes in the hydrocarbon stream 12 may be less than 10 wt % basedon the total weight of the hydrocarbon stream 12. Alternatively, theconcentration of naphthenes in the hydrocarbon stream 12 may be 10 wt %,20 wt %, 30 wt %, 40 wt % or more based on the total weight of thehydrocarbon stream 12. While embodiments include naphthenes of carbonnumbers up to 8, the disclosure is not limited to carbon number 8 as anupper end-point of the suitable range of naphthenes, and the naphthenescan include higher carbon numbers, e.g., 9, 10, 11, 12, 13, 14, 15, 16,17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, and higher. Inembodiments, at least a portion of the naphthenes in the hydrocarbonstream 12 comprise at least a portion of the heavy hydrocarbonmolecules.

Any aromatic hydrocarbon may be included in the hydrocarbon stream 12.Aromatic hydrocarbons suitable for use in the hydrocarbon stream 12include, but are not limited to, benzene, toluene, xylenes, ethylbenzene, or combinations thereof. In an embodiment, the concentration ofaromatic hydrocarbons in the hydrocarbon stream 12 may be less than 10wt % based on the total weight of the hydrocarbon stream 12.Alternatively, the concentration of aromatic hydrocarbons in thehydrocarbon stream 12 may be 10 wt %, 20 wt %, 30 wt %, 40 wt % or morebased on the total weight of the hydrocarbon stream 12. Whileembodiments include aromatic hydrocarbons of carbon numbers up to 8, thedisclosure is not limited to carbon number 8 as an upper end-point ofthe suitable range of aromatic hydrocarbons, and the aromatichydrocarbons can include higher carbon numbers, e.g., 9, 10, 11, 12, 13,14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, andhigher. In an embodiment, the aromatic hydrocarbons carbon number is ashigh as 22. In embodiments, at least a portion of the aromatics in thehydrocarbon stream 12 comprise at least a portion of the heavyhydrocarbon molecules.

In an embodiment, the hydrocarbon stream 12 comprises no aromatichydrocarbons.

As discussed herein, embodiments of the processes disclosed hereincontemplate hydrocracking of molecules, and in particular, heavyhydrocarbon molecules of the hydrocarbon stream 12. As such, it iscontemplated that at least a portion of the pyrolysis oils comprisesheavy hydrocarbon molecules (e.g., also referred to as heavy ends of thepyrolysis oils). Hydrocracking of the heavy ends of the pyrolysis oilsto meet steam cracker 50 specifications is contemplated. In anembodiment, the concentration of heavy hydrocarbon molecules in thehydrocarbon stream 12 may be less than 10 wt % based on the total weightof the hydrocarbon stream 12. Alternatively, the concentration of theheavy hydrocarbon molecules in the hydrocarbon stream 12 may be 10 wt %to 90 wt % based on the total weight of the hydrocarbon stream 12. Asdescribed above, the heavy hydrocarbon molecules may include paraffins,i-paraffins, olefins, naphthenes, aromatic hydrocarbons, or combinationsthereof. In embodiments, the heavy hydrocarbon molecules may include C₁₆and larger hydrocarbons. Greater than 5, 10, 15, 20, 25, 30 wt % or moreof the heavy hydrocarbon molecules in the hydrocarbon stream 12 ishydrocracked when the hydrocarbon stream 12 is contacted with thehydroprocessing catalyst in the hydroprocessing reactor 20. In anembodiment, the hydrocarbon stream 12 may have 2 wt % or less in aliquid phase which boils above 370° C.

Chloride compounds which may be included in the hydrocarbon stream 12include, but are not limited to, aliphatic chlorine-containinghydrocarbons, aromatic chlorine-containing hydrocarbons, and otherchlorine-containing hydrocarbons. Examples of chlorine-containinghydrocarbons include, but are not limited to, 1-chlorohexane (C₆H₁₃Cl),2-chloropentane (C₅H₁₁Cl), 3-chloro-3-methyl pentane (C₆H₁₃Cl),(2-chloroethyl) benzene (C₈H₉Cl), chlorobenzene (C₆H₅Cl), orcombinations thereof. The concentration of chloride compounds in thehydrocarbon stream 12 may be 5 ppm, 6 ppm, 7 ppm, 8 ppm, 9 ppm, 10 ppm,15 ppm, 20 ppm, 30 ppm, 40 ppm, 50 ppm, 100 ppm, 200 ppm, 300 ppm, 400ppm, 500 ppm, 600 ppm, 700 ppm, 800 ppm, 900 ppm, 1,000 ppm, 1,100 ppm,1,200 ppm, 1,300 ppm, 1,400 ppm, 1,500 ppm, 1,600 ppm, 1,700 ppm, 1,800ppm, 1,900 ppm, 2,000 ppm or more based on the total weight of thehydrocarbon stream 12.

Sulphides which may be included in the hydrocarbon stream 12 includesulphur-containing compounds. For example, a sulphiding agent such asdimethyl disulphide (C₂H₆S₂), dimethyl sulphide (C₂H₆S), mercaptans(R—SH), carbon disulphide (CS₂), hydrogen sulphide (H₂S), orcombinations thereof may be used as the sulphide in the hydrocarbonstream 12.

In an embodiment, one or more sulphides (e.g., dimethyl disulphide(C₂H₆S₂), dimethyl sulphide (C₂H₆S), mercaptans (R—SH), carbondisulphide (CS₂), hydrogen sulphide (H₂S), or combinations thereof) areadded to the hydrocarbon stream 12 (e.g., the hydrocarbon stream 12 is“spiked” with one or more sulphides), for example, via a spiking stream14, before the hydrocarbon stream 12 is introduced to thehydroprocessing reactor 20. In such embodiments, the one or moresulphides are added to the hydrocarbon stream 12 in an amount such thata sulphur content of the hydrocarbon stream 12, after sulphide addition,is about 0.5 wt %, 1 wt %, 1.5 wt %, 2 wt %, 2.5 wt %, 3 wt %, 3.5 wt %,4 wt %, 4.5 wt %, 5 wt % or more based on the total weight of thehydrocarbon stream 12. In embodiments, the spiking stream 14 may includecomponents tailored for spiking such as hexadecane and dimethyldisulphide; alternatively, the spiking stream 14 may be a heavier oil(e.g., naphtha, diesel, or both) which already contains sulphidecompounds (or to which sulphides are spiked to achieve the sulphurcontent disclosed herein) and which is blended with the hydrocarbonstream 12 to achieve the sulphur content described above.

In alternative embodiments, one or more sulphides are present in thehydrocarbon stream as a result of upstream processing from which thehydrocarbon stream 12 flows. In such embodiments, the hydrocarbon stream12 may contain one or more sulphides in an amount such that a sulphurcontent of the hydrocarbon stream 12, without sulphide spiking, is about0.5 wt %, 1 wt %, 1.5 wt %, 2 wt %, 2.5 wt %, 3 wt %, 3.5 wt %, 4 wt %,4.5 wt %, 5 wt % or more based on the total weight of the hydrocarbonstream 12.

In yet other embodiments, the hydrocarbon stream 12 may contain one ormore sulphides in an amount insufficient for sulphiding (e.g., less than5,000, 4,000, 3,000, 2,000, 1,000, 900, 800, 700, 600, 500, 400, 300,200, 100, 90, 80, 70, 60, 50, 40, 30, 20, 10, 5, or 1 ppm) thehydroprocessing catalyst contained in the hydroprocessing reactor 20(the catalyst is discussed in more detail below), and spiking stream 14is utilized to raise the concentration of the one or more sulphides inthe hydrocarbon stream to such that a sulphur content of the hydrocarbonstream 12, after sulphide addition, is about 0.5 wt %, 1 wt %, 1.5 wt %,2 wt %, 2.5 wt %, 3 wt %, 3.5 wt %, 4 wt %, 4.5 wt %, 5 wt % or morebased on the total weight of the hydrocarbon stream 12.

In an embodiment, the sulphur content of the hydrocarbon stream 12,after sulphide addition using spiking stream 14, is up to about 3 wt %based on the total weight of the hydrocarbon stream 12. In anotherembodiment, the sulphur content of the hydrocarbon stream 12, withoutsulphide addition using spiking stream 14, is up to about 3 wt % basedon the total weight of the hydrocarbon stream 12.

The hydroprocessing reactor 20 is configured to dechlorinate,hydrogenate, and hydrocrack components of the hydrocarbon stream 12 fedto the hydroprocessing reactor 20. In the hydroprocessing reactor 20,the hydrocarbon stream 12 is contacted with the hydroprocessing catalystin the presence of hydrogen to yield a hydrocarbon product in stream 22.It is contemplated the hydrocarbon stream 12 may be contacted with thehydroprocessing catalyst in upward flow, downward flow, radial flow, orcombinations thereof, with or without a staged addition of hydrocarbonstream 12, spiking stream 14, a H₂ stream 24, or combinations thereof.It is further contemplated the components of the hydrocarbon stream 12may be in the liquid phase, a liquid-vapor phase, or a vapor phase whilein the hydroprocessing reactor 20.

The hydroprocessing reactor 20 may facilitate any reaction of thecomponents of the hydrocarbon stream 12 in the presence of, or with,hydrogen. Reactions may occur as the addition of hydrogen atoms todouble bonds of unsaturated molecules (e.g., olefins, aromaticcompounds), resulting in saturated molecules (e.g., paraffins,i-paraffins, naphthenes). Additionally, reactions in the hydroprocessingreactor 20 may cause a rupture of a bond of an organic compound,resulting in “cracking” of a hydrocarbon molecule into two or moresmaller hydrocarbon molecules, or resulting in a subsequent reactionand/or replacement of a heteroatom with hydrogen. Examples of reactionswhich may occur in the hydroprocessing reactor 20 include, but are notlimited to, the hydrogenation of olefins, removal of heteroatoms fromheteroatom-containing hydrocarbons (e.g., dechlorination), hydrocrackingof large paraffins or i-paraffins to smaller hydrocarbon molecules,hydrocracking of aromatic hydrocarbons to smaller cyclic or acyclichydrocarbons, conversion of one or more aromatic compounds to one ormore cycloparaffins, isomerization of one or more normal paraffins toone or more i-paraffins, selective ring opening of one or morecycloparaffins to one or more i-paraffins, or combinations thereof.

In an embodiment, contacting the hydrocarbon stream 12 with thehydroprocessing catalyst in the presence of hydrogen yields ahydrocarbon product comprising C₁ to C₄ gases and C₅+ (C₅ and heavier)liquid hydrocarbons. As explained below, the separator 30 recovers theC₅+ liquid hydrocarbons in the treated hydrocarbon stream 32. The C₁ toC₄ gases can be recovered in hydroprocessed light gas stream 36.

In embodiments, the hydroprocessing reactor 20 may be any vesselconfigured to contain the hydroprocessing catalyst disclosed herein. Thevessel may be configured for gas phase, liquid phase, vapor-liquidphase, or slurry phase operation. The hydroprocessing reactor 20 mayinclude one or more beds of the hydroprocessing catalyst in fixed bed,fluidized bed, moving bed, ebullated bed, slurry bed, or combinationsthereof, configuration. The hydroprocessing reactor 20 may be operatedadiabatically, isothermally, nonadiabatically, non-isothermally, orcombinations thereof.

The reactions of this disclosure may be carried out in a single stage orin multiple stages. For example, the hydroprocessing reactor 20 can betwo reactor vessels fluidly connected in series, each having one or morecatalyst beds of the hydrogenating catalyst. Alternatively, two or morestages for hydroprocessing may be contained in a single reactor vessel.In embodiments having multiple stages, the first stage may dechlorinateand hydrogenate components of the hydrocarbon stream 12 to yield a firsthydrocarbon product having a first level of chloride compounds andolefins. The first hydrocarbon product may flow from the first stage tothe second stage, where other components of the first hydrocarbonproduct are dechlorinated and hydrogenated to yield a second hydrocarbonproduct stream (stream 22 in FIG. 1) having a second level of chloridecompounds and olefins. In either one or multiple reactors, the sulphurpresent in the feed is also removed as H₂S to provide a reduced level ofsulphur (e.g., sulphur content less than 200, 100, 90, 80, 70, 60, 50,40, 30, 20, 10, 9, 8, 7, 6, 5, 4, 3, 2, 1, 0.5, 0.1 ppmw S based ontotal weight of stream 22) acceptable for downstream processing in steamcracker 50 and refinery units. The second hydrocarbon stream may then betreated as described herein for stream 22.

Embodiments of the disclosure contemplate a second hydroprocessingreactor and a second hydroprocessing separator may be placed in betweenseparator 30 and treated hydrocarbon stream 32. The treated productflowing from the separator 30, in such embodiments, may contain residualsulphur, and the second hydroprocessing reactor/second separatorcombination may treat the treated product flowing from the separator 30to completely remove the sulphur such that a second treated productflowing in the treated hydrocarbon stream 32 from the second separatorcontains less than 200, 100, 90, 80, 70, 60, 50, 40, 30, 20, 10, 9, 8,7, 6, 5, 4, 3, 2, 1, 0.5, 0.1 ppmw S based on total weight of thetreated hydrocarbon stream 32. In embodiments having a secondhydroprocessing reactor, C₁ to C₄ hydrocarbon gases generated in thesecond hydroprocessing reactor may flow from the second hydroprocessingreactor in a second hydroprocessed light gas stream. Similar to thehydroprocessed light gas stream 36 flowing from the separator 30, thesecond hydroprocessed light gas stream may flow directly to the steamcracker 50, may flow to a light gas scrubbing unit 60 and then to thesteam cracker 50, or may be blended with another light gas (treated ornot) stream before flowing to the steam cracker 50.

In an embodiment, the hydroprocessing reactor 20 may comprise one ormore vessels.

In embodiments of a single vessel or multiple vessels, the sulphurpresent in the hydrocarbon stream 12 is removed as H₂S to provide areduced level of sulphur acceptable for downstream processing in steamcrackers and refinery units.

In an embodiment, hydrogen may feed to the hydroprocessing reactor 20 instream 24. The rate of hydrogen addition to the hydroprocessing reactor20 is generally sufficient to achieve the hydrogen-to-hydrocarbon ratiosdisclosed herein.

The disclosed hydroprocessing reactor 20 may operate at various processconditions. For example, contacting the hydrocarbon stream 12 with thehydroprocessing catalyst in the presence of hydrogen may occur in thehydroprocessing reactor 20 at a temperature of 100° C. to 450° C.;alternatively, 100° C. to 350° C.; or alternatively, 260° C. to 350° C.Contacting the hydrocarbon stream 12 with the hydroprocessing catalystin the presence of hydrogen may occur in the hydroprocessing reactor 20at a pressure of 1 barg to 200 barg; or alternatively, 20 barg to 60barg. Contacting the hydrocarbon stream 12 with the hydroprocessingcatalyst in the presence of hydrogen may occur in the hydroprocessingreactor 20 at a weight hourly space velocity (WHSV) of between 0.1 hr⁻¹to 10 hr⁻¹; or alternatively, 1 hr⁻¹ to 3 hr⁻¹. Contacting thehydrocarbon stream 12 with the hydroprocessing catalyst in the presenceof hydrogen may occur in the hydroprocessing reactor 20 at ahydrogen-to-hydrocarbon (H₂/HC) flow ratio of 10 to 3,000 NL/L; oralternatively, 200 to 800 NL/L.

It is contemplated that dechlorination using the hydroprocessingcatalyst as described herein is performed in the hydroprocessing reactor20 without the use of chlorine sorbents, without addition of Na₂CO₃ inan effective amount to function as a dechlorinating agent, or both.

The hydroprocessing catalyst may be any catalyst used for hydrogenation(e.g., saturation) of olefins and aromatic hydrocarbons (e.g., acommercially available hydrotreating catalyst). In an embodiment, thehydroprocessing catalyst is a cobalt and molybdenum catalyst (Co—Mocatalyst) on an alumina support. In other embodiments, thehydroprocessing catalyst is a nickel and molybdenum catalyst (Ni—Mocatalyst) on an alumina support or tungsten and molybdenum catalyst(W—Mo catalyst) on an alumina support. Other catalyst embodiments mayinclude platinum and palladium catalyst (Pt—Pd catalyst) on an aluminasupport, nickel sulphides suitable for slurry processing, molybdenumsulphides suitable for slurry processing, nickel and molybdenumsulphides, or combinations thereof. In embodiments where the hydrocarbonstream 12 comprises one or more sulphides and one or more chloridecompounds, contacting the hydrocarbon carbon stream 12 with thehydroprocessing catalyst acts to activate the hydroprocessing catalystby sulphiding and to acidify the hydroprocessing catalyst bychlorinating. Continuously contacting the hydroprocessing catalyst withthe hydrocarbon stream 12 containing the one or more sulphides, the oneor more chloride compounds, or both, may maintain the catalyst activityon a continuous basis.

In embodiments, the hydroprocessing catalyst is activated and/or theactivity is maintained by sulphiding the hydroprocessing catalystin-situ. For example, the hydroprocessing catalyst may be sulphided(i.e., activated) and/or sulphiding (i.e., maintaining the catalystactivity) of the hydroprocessing catalyst may be performed (e.g.,maintaining the hydroprocessing catalyst in sulphided form isaccomplished) by continuously contacting the hydrocarbon stream 12containing one or more sulphides with the hydroprocessing catalyst. Theone or more sulphides may be included in the hydrocarbon stream 12 in anamount such that the sulphur content of the hydrocarbon stream 12 isabout 0.5 wt %, 1 wt %, 1.5 wt %, 2 wt %, 2.5 wt %, 3 wt %, 3.5 wt %, 4wt %, 4.5 wt %, or 5 wt % based on the total weight of the hydrocarbonstream 12.

Alternatively, the hydroprocessing catalyst may be sulphided (i.e.,activated) by contacting a catalyst activating stream 26 containing oneor more sulphides with the hydroprocessing catalyst for a period of time(e.g., 1, 2, 3, 4, 5, 6, 7, 8, 9 or more hours) sufficient to activatethe hydroprocessing catalyst (before contacting the hydrocarbon stream12 with the hydroprocessing catalyst). In such embodiments, the catalystactivating stream 26 may include a hydrocarbon carrier for the one ormore sulphides, such as hexadecane. The one or more sulphides may beincluded in the catalyst activating stream 26 in an amount such that thesulphur content of the catalyst activating stream 26 is about 0.5 wt %,1 wt %, 1.5 wt %, 2 wt %, 2.5 wt %, 3 wt %, 3.5 wt %, 4 wt %, 4.5 wt %,5 wt % or more based on the total weight of the catalyst activatingstream 26. After the hydroprocessing catalyst is activated with thecatalyst activating stream 26, flow of the catalyst activating stream 26may be discontinued, and sulphiding (i.e., maintaining the catalystactivity) of the hydroprocessing catalyst may be maintained (e.g.,maintaining the hydroprocessing catalyst in sulphided form isaccomplished) by continuously contacting the hydrocarbon stream 12containing one or more sulphides with the hydroprocessing catalyst. Theone or more sulphides may be included in the hydrocarbon stream 12 in anamount such that the sulphur content of the hydrocarbon stream 12 isabout 0.5 wt %, 1 wt %, 1.5 wt %, 2 wt %, 2.5 wt %, 3 wt %, 3.5 wt %, 4wt %, 4.5 wt %, or 5 wt % based on the total weight of the hydrocarbonstream 12.

In embodiments, sulphiding and maintaining the catalyst in sulphidedform may use two different concentrations of sulphur content in thehydrocarbon stream 12. For example, the one or more sulphides may beincluded (e.g., provided via spiking stream 14) in the hydrocarbonstream 12 in an amount such that the sulphur content of the hydrocarbonstream 12 is about 2 wt % based on the total weight of the hydrocarbonstream 12 for sulphiding, and the one or more sulphides may bemaintained (e.g., via spiking stream 14) in the hydrocarbon stream 12 inan amount such that the sulphur content of the hydrocarbon stream 12 isabout 2 wt % based on the total weight of the hydrocarbon stream 12 formaintaining the hydroprocessing catalyst in the sulphided form. Inanother example, the one or more sulphides may be included in thecatalyst activating stream 26 in an amount such that the sulphur contentof the catalyst activating stream 26 is about 3 wt % based on the totalweight of the catalyst activating stream 26 for sulphiding, and the oneor more sulphides may be included (e.g., via spiking stream 14) in thehydrocarbon stream 12 in an amount such that the sulphur content of thehydrocarbon stream 12 is about 2 wt % based on the total weight of thehydrocarbon stream 12 for maintaining the hydroprocessing catalyst inthe sulphided form.

In embodiments, catalyst activity is also maintained by chloriding thehydroprocessing catalyst. The hydroprocessing catalyst is chloridedusing the one more chloride compounds provided to the hydroprocessingcatalyst by the hydrocarbon stream 12. The one or more chloridecompounds which contribute to acidification of the hydroprocessingcatalyst may be included in the hydrocarbon stream 12 in concentrationsdisclosed herein.

Sulphiding and maintaining the hydroprocessing catalyst in sulphidedform result in a hydroprocessing catalyst which has hydrogenation sites(sulphided metal) for hydrogenation of components of the hydrocarbonstream 12. Chloriding the hydroprocessing catalyst results in ahydroprocessing catalyst which has hydrocracking sites (chloridealumina) for hydrocracking components of the hydrocarbon stream 12.

Due to hydrogenation reactions in the hydroprocessing reactor 20, inembodiments, the hydrocarbon product stream 22 may contain one or moreolefins in a concentration of less than 1 wt % based on the total weightof the hydrocarbon product stream 22. It is also contemplated that theconcentration of aromatic hydrocarbons in the hydrocarbon product stream22 is less than the concentration of aromatic hydrocarbons in thehydrocarbon stream 12 due to hydrogenation of at least a portion of thearomatic hydrocarbons in the hydroprocessing reactor 20. For example,aromatic hydrocarbons may be present in the hydrocarbon product stream22 in a concentration of less than 10, 9, 8, 7, 6, 5, 4, 3, 2, or 1 wt %based on the total weight of the hydrocarbon product stream 22. In anembodiment, the hydrocarbon product stream 22 may have 2 wt % or less ina liquid phase which boils above 370° C.

The reaction product flows as effluent from the hydroprocessing reactor20 in the hydrocarbon product stream 22 to the separator 30. Separator30 may be any vessel which can recover a treated hydrocarbon stream 32from the hydrocarbon product 22 which is fed to the separator 30. Inembodiments, the treated hydrocarbon stream 32 may be recovered byseparating a treated product (e.g., liquid product or gas product) fromsulphur and chlorine-containing gas in the separator 30, and flowing thetreated product in the treated hydrocarbon stream 32 from the separator30.

In an embodiment, the separator 30 is a condenser which operates atconditions which condense a portion of the hydrocarbon product stream 22into the treated product (e.g., liquid product or treated liquidproduct) while leaving sulphur and chlorine-containing compounds in thegas phase. The treated liquid product flows from the separator 30 intreated hydrocarbon stream 32, and the sulphur and chlorine-containinggas flows from the separator 30 via hydroprocessed light gas stream 36.In such embodiments, the treated liquid product may comprise C₅+ (C₅ andheavier) liquid hydrocarbons.

In another embodiment, the separator 30 is a scrubbing unit containing acaustic solution (e.g., a solution of sodium hydroxide in water) whichremoves (e.g., via reaction, adsorption, absorption, or combinationsthereof) sulphur and chlorine-containing gases from the hydrocarbonproduct stream 22 to yield the treated product which flows from theseparator 30 via treated hydrocarbon stream 32 while the C₁ to C₄hydrocarbons and sulphur and chlorine-containing compounds are removedfrom the separator 30 via hydroprocessed light gas stream 36. In suchembodiments, the treated liquid product may comprise C₅+ (C₅ andheavier) liquid hydrocarbons.

In yet another embodiment, the separator 30 is a condenser incommunication with one or more stages of a gas-liquid separatorpositioned downstream of the condenser and a scrubbing unit containing acaustic solution. As described above, the condenser may operate atconditions which condense a portion of the hydrocarbon product stream 22into a mid-treated product (e.g., liquid product or treated liquidproduct) while leaving sulphur and chlorine-containing compounds in thegas phase. In such embodiments, the mid-treated product may comprise C₅+(C₅ and heavier) liquid hydrocarbons. The mid-treated liquid product andthe mid-treated gas product flow from the first stage of the gas-liquidseparator, and the mid-treated gas product is treated in the scrubbingunit of the separator 30. The mid-treated liquid product flows out ofthe first stage of the gas-liquid separator and experiences a pressurereduction (e.g., via a valve or other pressure reducing device known inthe art with the aid of this disclosure), which creates an effluent gas(e.g., via flashing) which flows to the scrubbing unit for furtherremoval of sulphur and chlorine-containing compounds from the liquidhydrocarbons. The treated product flowing in hydrocarbon stream 32 flowsfrom the scrubbing unit of the separator 30 to the polishing zone 40 viastream 32. Sulphur and chlorine-containing compounds flow from theseparator 30 in hydroprocessed light gas stream 36.

In embodiments disclosed herein, no hydrogen halides and no halogenatedorganic compounds are recycled to the hydroprocessing reactor 20.

In embodiments, the treated hydrocarbon stream 32 includes one or morechloride compounds in a concentration of less than 5 ppm, 4 ppm, 3 ppm,2 ppm, 1 ppm, or 0.5 ppm based on a total weight of the treatedhydrocarbon stream 32. It is contemplated that the one or more chloridecompounds in the treated hydrocarbon stream 32 may be the same as someor all of the one or more chloride compounds in the hydrocarbon stream12; alternatively, it is contemplated that only some of the one or morechloride compounds in the treated hydrocarbon stream 32 are the same asonly some of the one or more chloride compounds in the hydrocarbonstream 12; alternatively, it is contemplated that none of the one ormore chloride compounds in the treated hydrocarbon stream 32 are thesame as the one or more chloride compounds in the hydrocarbon stream 12.

In additional embodiments, the treated hydrocarbon stream 32 includesthe one or more olefins in a concentration which is less than aconcentration of the one or more olefins in the hydrocarbon stream 12due to hydrogenation of at least a portion of the one or more olefinsfrom the hydrocarbon stream 12 while the hydrocarbon stream 12 iscontacted with the hydroprocessing catalyst in the hydroprocessingreactor 20. In yet additional embodiments, the treated hydrocarbonstream 32 includes the one or more olefins in a concentration which isless than a concentration of the one or more olefins in the hydrocarbonstream 12 due to hydrogenation and hydrocracking of at least a portionof the one or more olefins from the hydrocarbon stream 12 while thehydrocarbon stream 12 is contacted with the hydroprocessing catalyst inthe hydroprocessing reactor 20. In an embodiment, the one or moreolefins are present in the treated hydrocarbon stream 32 in aconcentration of less than 1 wt % based on the total weight of thetreated hydrocarbon stream 32.

In embodiments, the treated hydrocarbon stream 32 includes one or moreparaffins, and one or more olefins in a concentration of less than 1 wt% based on the total weight of the treated hydrocarbon stream 32. It isalso contemplated that the concentration of aromatic hydrocarbons in thetreated hydrocarbon stream 32 is less than the concentration of aromatichydrocarbons in the hydrocarbon stream 12 due to hydrogenation of atleast a portion of the aromatic hydrocarbons in the hydroprocessingreactor 20. For example, aromatic hydrocarbons may be present in thetreated hydrocarbon stream 32 in a concentration of less than 10, 9, 8,7, 6, 5, 4, 3, 2, or 1 wt % based on the total weight of the treatedhydrocarbon product stream 32.

In embodiments, the treated hydrocarbon stream 32 may have a reducedconcentration of heavy hydrocarbon molecules compared to theconcentration of heavy hydrocarbon molecules in the hydrocarbon stream12 due to hydrocracking of at least a portion of the heavy hydrocarbonmolecules from the hydrocarbon stream 12 while the hydrocarbon stream 12is contacted with the hydroprocessing catalyst. In further embodiments,the treated hydrocarbon stream 32 may comprise none of the heavyhydrocarbon molecules form the hydrocarbon stream 12 due tohydrocracking of the heavy hydrocarbon molecules in the hydroprocessingreactor 20. Due to hydrocracking of heavy hydrocarbon molecules when thehydrocarbon stream 12 is contacted with the hydroprocessing catalyst inthe hydroprocessing reactor 20, the treated hydrocarbon stream 32 mayhave a boiling end point of 370° C. In an embodiment, the treatedhydrocarbon stream 32 may have 2 wt % or less in a liquid phase whichboils above 370° C.

In embodiments where the treated hydrocarbon stream 32 includes one ormore chloride compounds in a concentration of less than 3 ppm, thetreated hydrocarbon product flowing in treated hydrocarbon stream 32 maybe fed directly to the steam cracker 50 by flowing through bypass stream34. In alternative embodiments where the treated hydrocarbon stream 32includes one or more chloride compounds in a concentration of 3 ppm ormore (e.g., 3 ppm to 5 ppm), the treated hydrocarbon stream 32 may flowto the polishing zone 40 in order to reduce the chloride content to meetthe requirements of the steam cracker 50.

To further reduce chloride content, embodiments of the processesdisclosed herein may include dechlorinating the treated hydrocarbonstream 32 to yield a polished hydrocarbon stream 42. Dechlorination mayoccur in the polishing zone 40. The polishing zone 40 may be considereda polishing stage in which the treated hydrocarbon stream 32 is“polished” to reduce the chloride content. In order to use thehydroprocessing catalyst in the hydroprocessing reactor 20 untilend-of-run conditions (e.g., in order to maintainhydrogenation/saturation performance), the operating temperature (e.g.,the catalyst bed temperature) of the hydroprocessing reactor 20 may beincreased. As the operating temperature of the hydroprocessing reactor20 is increased, operating conditions may not yield a chloride contentin the treated hydrocarbon stream 32 which meets the requirements forthe steam cracker 50 (e.g., at temperatures above 350° C. the treatedhydrocarbon stream 32 may have a chloride content 3-5 ppm and not lessthan 3 ppm as required by the steam cracker 50). In such embodiments,the treated hydrocarbon stream 32 may be diverted from flowing in thebypass stream 34 and may be directed to flow to the polishing zone 40for further chloride removal such that a polished hydrocarbon stream 42flowing from the polishing zone 40 has a concentration of one or morechlorides which meet the requirement of the steam cracker 50.

Similar to the hydroprocessed light gas stream 36 flowing from theseparator 30, a polished light gas stream 46 comprising C₁ to C₄ gasesgenerated in the polishing zone 40 (e.g., in hydroprocessing reactor 41of FIG. 2) may flow directly to the steam cracker 50, may flow to thelight gas scrubbing unit 60 and then to the steam cracker 50, or may beblended with another light gas (treated or not) stream before flowing tothe steam cracker 50.

In an embodiment, dechlorinating the treated hydrocarbon stream 32 mayinclude removing at least a portion of the one or more chloridecompounds remaining in the treated hydrocarbon stream 32 via adsorptivedechlorination to yield the polished hydrocarbon stream 42. Removal ofremaining chloride compounds may occur in the polishing zone 40 in theform of one or more adsorption units. The one or more adsorption unitsmay contain one or more adsorbents (e.g., goethite, hematite, magnetite,alumina, alumino-silicate, gamma alumina, or combinations thereof) whichremoves (e.g., via reaction, adsorption, absorption, or combinationsthereof) a portion of the one or more remaining chloride compounds fromthe treated hydrocarbon stream 32 to yield a polished hydrocarbonproduct which flows from the adsorption unit via polished hydrocarbonstream 42. One or more chloride compounds which are removed by thesorbent in the adsorption unit may be recovered from the adsorptionunit(s) via processes known in the art with the aid of this disclosure(e.g., regeneration of adsorption units operating in parallel). Anexample of an adsorption process suitable for use in the polishing zone40 is found in U.S. Patent Publication No. 2015/053,589, which is herebyincorporated by reference.

In an additional or alternative embodiment, dechlorinating the treatedhydrocarbon stream 32 may include contacting the treated hydrocarbonstream 32 with a second hydroprocessing catalyst in the presence ofhydrogen to yield a second hydrocarbon product. In such embodiments, thepolishing zone 40 may be a second hydroprocessing stage in the system100. That is, in embodiments, the polishing zone 40 may include anotherhydroprocessing reactor which is the second stage of hydroprocessing ina two-stage hydroprocessing configuration (the hydroprocessing reactor20 being the first stage). FIG. 2 illustrates a polishing zone 40 whichis a second stage of hydroprocessing.

Referring to FIG. 2, the hydroprocessing reactor 41 of the polishingzone 40 is configured to dechlorinate, hydrogenate, and hydrocrackcomponents of the treated hydrocarbon stream 32 fed to thehydroprocessing reactor 41. In the hydroprocessing reactor 41, thetreated hydrocarbon stream 32 is contacted with a second hydroprocessingcatalyst in the presence of hydrogen to yield a second hydrocarbonproduct in stream 43. It is contemplated the treated hydrocarbon stream32 may be contacted with the hydroprocessing catalyst in upward flow,downward flow, radial flow, or combinations thereof. It is furthercontemplated the components of the treated hydrocarbon stream 32 may bein the liquid phase, a liquid-vapor phase, or a vapor phase while in thehydroprocessing reactor 41.

The hydroprocessing reactor 41 may facilitate dechlorination of thetreated hydrocarbon stream 32 in the presence of, or with, hydrogen.Other reactions in addition to dechlorination reactions may occur inhydroprocessing reactor 41, for example, the reactions discussed forhydroprocessing reactor 20.

In embodiments, the hydroprocessing reactor 41 may be any vesselconfigured to contain the hydroprocessing catalyst disclosed herein. Thevessel may be configured for gas phase, liquid phase, vapor-liquidphase, or slurry phase operation. The hydroprocessing reactor 41 mayinclude one or more beds of the second hydroprocessing catalyst in fixedbed, fluidized bed, moving bed, ebullated bed, slurry bed, orcombinations thereof, configuration. The hydroprocessing reactor 41 maybe operated adiabatically, isothermally, nonadiabatically,non-isothermally, or combinations thereof.

In an embodiment, hydrogen may feed to the hydroprocessing reactor 41 instream 44. The rate of hydrogen addition to the hydroprocessing reactor41 is generally sufficient to achieve the hydrogen-to-hydrocarbon ratiosdisclosed herein.

The hydroprocessing reactor 41 may operate within the same ranges fortemperature, pressure, weight hourly space velocity (WHSV), andhydrogen-to-hydrocarbon (H₂/HC) flow ratio disclosed for hydroprocessingreactor 20. In embodiments, while the hydroprocessing reactor 20 andhydroprocessing reactor 41 may operate within the same ranges, thevalues for temperature, pressure, weight hourly space velocity (WHSV),and hydrogen-to-hydrocarbon (H₂/HC) flow ratio of the hydroprocessingreactor 41 may or may not be the same as the values for temperature,pressure, weight hourly space velocity (WHSV), andhydrogen-to-hydrocarbon (H₂/HC) flow ratio of the hydroprocessingreactor 20. For example, hydroprocessing reactor 41 may operate at thesame temperature, pressure, weight hourly space velocity (WHSV), orhydrogen-to-hydrocarbon (H₂/HC) flow ratio as hydroprocessing reactor20, while all other conditions are not the same.

It is contemplated that dechlorination using the second hydroprocessingcatalyst as described herein is performed in the hydroprocessing reactor41 without the use of chlorine sorbents, without addition of Na₂CO₃ inan effective amount to function as a dechlorinating agent, or both.

The second hydroprocessing catalyst used in the hydroprocessing unit 41may be any catalyst used for hydrogenation (e.g., saturation) of olefinsand aromatic hydrocarbons (e.g., a commercially available hydrotreatingcatalyst). In an embodiment, the second hydroprocessing catalyst is acobalt and molybdenum catalyst (Co—Mo catalyst) on an alumina support.In other embodiments, the second hydroprocessing catalyst is a nickeland molybdenum catalyst (Ni—Mo catalyst) on an alumina support ortungsten and molybdenum catalyst (W—Mo catalyst) on an alumina support.Other second catalyst embodiments may include platinum and palladiumcatalyst (Pt—Pd catalyst) on an alumina support, nickel sulphidessuitable for slurry processing, molybdenum sulphides suitable for slurryprocessing, nickel and molybdenum sulphides, or combinations thereof. Inembodiments where the treated hydrocarbon stream 32 comprises one ormore chloride compounds, contacting the treated hydrocarbon carbonstream 32 with the second hydroprocessing catalyst acts to acidify thesecond hydroprocessing catalyst by chlorinating.

In embodiments, the second hydroprocessing catalyst is chlorided usingthe one more chloride compounds provided to the second hydroprocessingcatalyst by the treated hydrocarbon stream 32. The one or more chloridecompounds which contribute to acidification of the secondhydroprocessing catalyst may be in the treated hydrocarbon stream 32 inconcentrations disclosed herein, e.g., 3 to 5 ppm. Chloriding the secondhydroprocessing catalyst results in a hydroprocessing catalyst which hashydrocracking sites (chloride alumina) for hydrocracking components ofthe treated hydrocarbon stream 32.

While hydrogenation in hydroprocessing reactor 41 may occur withoutsulphiding, in embodiments where further hydrogenation is desired, thesecond hydroprocessing catalyst may be sulphided in the same manner asdisclosed for the first hydroprocessing catalyst in the hydroprocessingreactor 20 (e.g., treated hydrocarbon stream 32 may be spiked withsulphides via a spiking stream, a catalyst activating stream may providesulphides to the hydroprocessing reactor 41, or both).

Due to hydrocracking reactions in the hydroprocessing reactor 41, inembodiments, the polished hydrocarbon stream 43 may contain fewer heavyhydrocarbon molecules than treated hydrocarbon stream 32. The polishedhydrocarbon product stream 43 may also contain one or more olefins in aconcentration of less than 1 wt % based on the total weight of thepolished hydrocarbon product stream 43 (e.g., either via furtherhydrogenation in hydroprocessing reactor 41, via the hydrogenation whichoccurs in hydroprocessing reactor 20, or both).

The reaction product of the second hydroprocessing reactor 41 flows aseffluent from the hydroprocessing reactor 41 in the polished hydrocarbonproduct stream 43 to the second separator 45. Separator 45 may be anyvessel which can recover a polished hydrocarbon stream 42 from thepolished hydrocarbon product stream 43 which is fed to the separator 45.In embodiments, the polished hydrocarbon stream 42 may be recovered byseparating a polished product (e.g., liquid product or gas product) fromchlorine-containing gas in the separator 45, and flowing the polishedproduct in the polished hydrocarbon stream 42 from the separator 45.

In an embodiment, the separator 45 is a condenser which operates atconditions which condense a portion of the polished hydrocarbon productstream 43 into the polished product (e.g., liquid product or polishedliquid product) while leaving chlorine-containing compounds in the gasphase. The polished liquid product flows from the separator 45 inpolished hydrocarbon stream 42, and the chlorine-containing gas flowsfrom the separator 45 via gas stream 47 or from the hydroprocessingreactor 41 via stream 46.

In another embodiment, the separator 45 is a scrubbing unit containing acaustic solution (e.g., a solution of sodium hydroxide in water) whichremoves (e.g., via reaction, adsorption, absorption, or combinationsthereof) chlorine-containing gases from the polished hydrocarbon productstream 43 to yield the polished product (e.g., gas product or treatedgas product) which flows from the separator 45 via polished hydrocarbonstream 42 while the chlorine-containing compounds in the gas phase flowfrom the separator 45 via chloride stream 47.

In yet another embodiment, the separator 45 is a polishing condenser incommunication with one or more stages of a gas-liquid separator whichare downstream of the condenser, and a polishing scrubbing unitcontaining a caustic solution. As described above, the condenser mayoperate at conditions which condense a portion of the polishedhydrocarbon product stream 43 into a mid-treated polished product whileleaving chlorine-containing compounds in the gas phase. The gases flowinto the polishing scrubbing unit from the gas-liquid separator keptdownstream of the condenser, to provide a sulphur-free and chloride-freetreated gas. In such embodiments, the mid-treated polished product maycomprise C₅+ (C₅ and heavier) liquid hydrocarbons. The mid-treatedpolished liquid product flows from the first stage of the gas-liquidseparator and experiences a pressure reduction (e.g., via a valve orother pressure reducing device known in the art with the aid of thisdisclosure) and flows into a second stage of the gas-liquid separator,which creates an effluent gas (e.g., via flashing) which flows to thepolishing scrubbing unit for further removal of chlorine-containingcompounds from the liquid hydrocarbons. The treated product flowing inpolished hydrocarbon stream 42 flows from the second stage of thegas-liquid separator of the separator 45 to the steam cracker 50.

In embodiments disclosed herein, no hydrogen halides and no halogenatedorganic compounds are recycled to the hydroprocessing reactor 41.

Embodiments of the disclosed processes also contemplate the polishingzone 40 may include one or more adsorption units as described above inseries with a second hydroprocessing reactor 41/separator 45 of FIG. 2,where the adsorption unit dechlorinates the treated hydrocarbon stream32 and passes an intermediate stream to the second hydroprocessingreactor 41 for further dechlorination to yield the polished hydrocarbonstream 42 having a chloride content required for the steam cracker 50,e.g., less than 3 ppm chlorides. Alternatively, instead of beingupstream of second hydroprocessing reactor 41, the adsorption unit canbe directly downstream of the second hydroprocessing reactor 41.

In embodiments, the polished hydrocarbon stream 42 includes one or morechloride compounds in a concentration of less than 3 ppm, 2 ppm, 1 ppm,or 0.5 ppm based on a total weight of the polished hydrocarbon stream42. It is contemplated that the one or more chloride compounds in thepolished hydrocarbon stream 42 may be the same as some or all of the oneor more chloride compounds in the treated hydrocarbon stream 32 and/orhydrocarbon stream 12; alternatively, it is contemplated that only someof the one or more chloride compounds in the polished hydrocarbon stream42 are the same as only some of the one or more chloride compounds inthe treated hydrocarbon stream 32 and/or the hydrocarbon stream 12;alternatively, it is contemplated that none of the one or more chloridecompounds in the polished hydrocarbon stream 42 are the same as the oneor more chloride compounds in the treated hydrocarbon stream 32 and/orthe hydrocarbon stream 12.

In additional embodiments, the polished hydrocarbon stream 42 includesthe one or more olefins in a concentration of less than 1 wt % based onthe total weight of the polished hydrocarbon stream 42. In embodiments,the polished hydrocarbon stream 42 may have a reduced concentration ofheavy hydrocarbon molecules compared to the concentration of heavyhydrocarbon molecules in the treated hydrocarbon stream 32 due tohydrocracking of at least a portion of the heavy hydrocarbon moleculesfrom the treated hydrocarbon stream 32 while the treated hydrocarbonstream 32 is contacted with the second hydroprocessing catalyst in thehydroprocessing reactor 41. In embodiments, the polished hydrocarbonstream 42 may have a boiling end point of 370° C.

In embodiments where the polished hydrocarbon stream 42 includes one ormore chloride compounds in a concentration of less than 3 ppm, thepolished hydrocarbon product flowing in polished hydrocarbon stream 42may be fed directly to the steam cracker 50 (e.g., without fractionationor separation before flowing to the steam cracker 50).

Steam cracker 50 generally has feed specification requirements. First,the steam cracker 50 requires the concentration of chloride compounds inthe feed to the steam cracker 50 to be less than 3 ppm. Second, thesteam cracker 50 requires the concentration of olefins in a stream fedto the steam cracker 50 to be less than 1 wt %. Third, the steam cracker50 requires the boiling end point of the stream fed to the steam cracker50 to be 370° C. The steam cracker 50 cracks molecules or cleaves atelevated temperatures carbon-carbon bonds of the components in thebypass stream 34 or polished hydrocarbon stream 42 in the presence ofsteam to yield high value products such as ethylene, propylene, butene,butadiene, aromatic compounds, or combinations thereof. Likewise, inembodiments having light gas streams 16 and/or 46, the steam cracker 50cracks molecules or cleaves at elevated temperatures carbon-carbon bondsof the components in the treated light gas product (e.g., of treatedpyrolysis light gas stream 62 and/or treated hydroprocessed light gasstream 64) in the presence of steam to yield high value products such asethylene, propylene, butene, butadiene, aromatic compounds, orcombinations thereof. The high value products may flow from the steamcracker 50 via stream 52.

One or more of the pyrolysis gases (e.g., C₁ to C₄ gases) in thepyrolysis light gas stream 16, the C₁ to C₄ gases in the hydroprocessedlight gas stream 36, and the C₁ to C₄ gases in the polished light gasstream 46 may flow to a light gas scrubbing unit 60. The C₁ to C₄ gasesmay be C₁ to C₄ hydrocarbons. The light gas scrubbing unit 60 may be thesame scrubbing unit used in embodiments of the separator 30 whichinclude a scrubbing unit, or the light gas scrubbing unit 60 may be inaddition to any scrubbing unit included in the separator 30. Asdescribed for the scrubbing unit of the separator 30, the light gasscrubbing unit 60 may contain a caustic solution (e.g., a solution ofsodium hydroxide in water) which removes (e.g., via reaction,adsorption, absorption, or combinations thereof) sulphur andchlorine-containing gases from the stream (e.g., pyrolysis light gasstream 16 and/or hydroprocessed light gas stream 46) fed to the lightgas scrubbing unit 60 and yield a treated light gas product (e.g.,treated pyrolysis light gas stream 62, treated hydroprocessed light gasstream 64, or a single treated light gas stream which combines thetreated hydroprocessed product and treated pyrolysis product) whichflows from the light gas scrubbing unit 60 to the steam cracker 50. Theremoved compounds (sulphur and/or chlorine containing gases) may flowfrom the scrubbing unit 60 in stream 66.

In embodiments utilizing light gas scrubbing unit 60, the treatedpyrolysis light gas stream 62 may include one or more sulphide and/orchloride compounds in a concentration of less than 5 ppm, 4 ppm, 3 ppm,2 ppm, 1 ppm, or 0.5 ppm based on a total weight of the treatedpyrolysis light gas stream 62.

In embodiments utilizing scrubbing unit 60, the treated hydroprocessedlight gas stream 64 may include one or more sulphide and/or chloridecompounds in a concentration of less than 5 ppm, 4 ppm, 3 ppm, 2 ppm, 1ppm, or 0.5 ppm based on a total weight of the treated hydroprocessedlight gas stream 64.

It is contemplated that embodiments of the disclosure may utilizeblending with a non-chlorinated stream in various locations of thesystem 100. For example, a non-chlorinated stream may be blended withbypass stream 34 to achieve the feed specification requirements forchlorine content, olefin content, boiling end point, sulphur content, orcombinations thereof for the steam cracker 50. In another example, anon-chlorinated stream may be blended with treated hydrocarbon stream 32to lower the chlorine content, olefin content, boiling end point,sulphur content, or combinations thereof such that subsequent treatmentin the polishing zone 40 achieves the feed specification requirementsfor the steam cracker 50. In another example, a non-chlorinated streammay be blended with polished hydrocarbon stream 42 to achieve the feedspecification requirements for chlorine content, olefin content, boilingend point, sulphur content, or combinations thereof for the steamcracker 50. Utilizing a blending stream provides a mechanism by whichthe chloride content, sulphur content, olefin content, and boiling endpoint can be adjusted to meet feed specification requirements of thesteam cracker 50 without additional capital expenditure on equipment.

The foregoing describes a system 100 which implements one or moreembodiments of a robust integrated process for the conversion of wasteplastics to high value products. The robust integrated processes allowfor operation with a single hydroprocessing reactor 20 which providessimultaneous hydrogenation, dechlorination, and hydrocracking ofcomponents of a hydrocarbon stream 12 to specifications which meet steamcracker 50 requirements, with the option to further dechlorinate thetreated hydrocarbon stream 32 in a polishing zone 40, for example, whenthe hydroprocessing reactor 20 conditions are modified to maintainhydrogenation/saturation efficiency at the expense of dechlorinationefficiency. In such scenarios, it is possible that chloride levels inthe treated hydrocarbon stream 32 do not meet requirements of steamcracker 50 because the concentration of one or more chloride compoundsin the treated hydrocarbon stream 32 is not less than 3 ppm, forexample, the concentration is 3-5 ppm. As such, the polishing zone 40provides for further dechlorination to meet the chloride contentrequirement of the steam cracker 50. In embodiments where the polishingzone 40 is a second hydroprocessing reactor 41, hydrocracking,hydrogenation, or both, of the components of the treated hydrocarbonstream 32 may also occur in addition to dechlorination.

When operating with a single hydroprocessing step in hydroprocessingreactor 20, the treated hydrocarbon stream 32 is suitable for feedingdirectly to steam cracker 50, without separations or fractionations ofthe treated hydrocarbon product. When operating with use of thepolishing zone 40, the treated hydrocarbon stream 32 is “polished” toyield polished hydrocarbon stream 42 without fractionation or furtherseparation of the polished hydrocarbon stream 42.

Catalyst activity of the hydroprocessing catalyst can be initiatedand/or maintained simultaneously with the simultaneous hydrogenation,dechlorination, and hydrocracking by using streams of the compositionsdisclosed herein which feed to a hydroprocessing reactor.

The hydroprocessing catalyst in hydroprocessing reactor 20 may be thesame or different from the hydroprocessing catalyst in thehydroprocessing reactor 41. In embodiments where the hydroprocessingcatalyst is the same for both first hydroprocessing reactor 20 andsecond hydroprocessing reactor 41, the operating conditions of thereactors 20 and 41 may be adjusted to achieve the desired feedspecifications for steam cracker 50. In addition, catalyst sulphidingmay be adjusted. For example, first hydroprocessing catalyst in thehydroprocessing reactor 20 may be sulphided as disclosed herein whilethe second hydroprocessing catalyst in the hydroprocessing reactor 41 isnot sulphided via the techniques disclosed herein. By not sulphiding thesecond hydroprocessing catalyst, the first hydroprocessing catalyst canbe tuned for simultaneous hydrogenation, dechlorination, andhydrocracking while the second hydroprocessing catalyst can be tuned fordechlorination and hydrocracking (some hydrogenation may occur; however,the concentration of sulphided metal sites which provide forhydrogenation by the second hydroprocessing catalyst is less than theconcentration of sulphided metal sites provided by the firsthydroprocessing catalyst). The robustness of the disclosed processes mayalso allow for intermittent sulphiding of the second hydroprocessingcatalyst in the hydroprocessing reactor 41 in order to adjust the degreeof hydrogenation in the second hydroprocessing reactor as a result offluctuations in the hydrogenation efficiency in the firsthydroprocessing reactor 20.

Examples provided below demonstrate the various embodiments of thepyrolysis process for generating a pyrolysis oil or hydrocarbon stream,not limited by the equipment used. These examples are for high severitypyrolysis process carried out at temperatures of 450° C. to 750° C., lowseverity pyrolysis process carried out at 250° C. to 450° C., hydrogenor hydrogen donor assisted (hydropyrolysis) processes carried out atboth the above severities as well as use of a catalyst recipe and acombination of sand and catalyst as a catalyst recipe. Though theseexamples are provided for fluidized beds where in the heat transfer andcatalyst/feed contact are good, directionally the same type of resultscan be obtained with other types of pyrolysis equipment as describedherein.

Also, as is demonstrated in the examples below and discussed above, ithas been found that hydrocracking of olefins and heavy hydrocarbonmolecules contained in a hydrocarbon stream occurs using ahydroprocessing catalyst at the conditions disclosed herein. The olefinsare hydrogenated in addition to being hydrocracked. Moreover, chloridecompounds contained in the hydrocarbon stream are removed usinghydroprocessing catalyst. Hydrocracking according to the embodimentsdisclosed herein can occur over the operating pressures disclosed hereinfor hydroprocessing reactor 20, including those low pressuresdemonstrated in the examples. Embodiments of the processes disclosedherein meet the boiling end point of 370° C. required for steamcrackers. Moreover, the disclosed embodiments demonstrate that about 30wt % of the heavy hydrocarbon molecules of a hydrocarbon stream canundergo hydrocracking at the conditions disclosed herein. When thehydrocarbon stream contains plastic and/or tire pyrolysis oil, theheavier ends of the pyrolysis oil are hydrocracked. Increased levels ofparaffins due to the hydrocracking ability of the processes disclosedherein can result in a higher production of propylene in steam crackers.LPG gases are not liberated in the disclosed processes until thetemperature of the one or more catalyst beds in the hydroprocessingreactor 20 reaches about 400° C. Gas product formation is minimized,which is useful for existing plants which are constrained on the gasflow rate to the gas compressor section. In the disclosed embodiments,the production of methane and ethane is also low.

Dechlorination according to the embodiments disclosed herein can occurover the operating temperature ranges disclosed herein for thehydroprocessing reactor 20, including operating temperatures in thelow-end of the temperature ranges disclosed herein. Removal of chloridecompounds to less than 1 ppm occurs at temperatures below 350° C.Moreover, achieving sub-ppm chloride compound concentrations is possiblewith initial chloride content in the hydrocarbon stream 12 of 1,000 ppmor more. Moreover still, removal of chloride compounds is effective fordifferent types and classes of chlorides present in the hydrocarbonstream 12. When the hydroprocessing reaction is conducted attemperatures at or above 350° C., it has been found that the treatedhydrocarbon product contains 3 ppm or higher chloride content. In suchcases, blending with a non-chlorinated stream can be utilized. Forexample, the treated hydrocarbon product stream 32, bypass stream, 34,polished hydrocarbon stream 42, or combinations thereof can be blendedwith a non-chlorinated stream in such proportions to make the combinedblended treated hydrocarbon stream meet the steam cracker feedspecifications.

Operation at low temperatures (e.g., less than 350° C.) also has anadded advantage of corrosion mitigation of the reactor metallurgy. Formost metals and alloys used in the commercial reactors, corrosion ratesstart to increase at reactor temperatures over 300° C. It has been foundthat the efficiency of dechlorination according to the disclosedembodiments is good at reactor temperatures below 350° C., and thedechlorination process works with a sulphided Co—Mo catalyst on analumina support even as low as 260° C., with the chlorides in thetreated product being less than 1 ppm. Thus, the metallurgy corrosionissue is mitigated and longer equipment life is possible while achievingdechlorination to levels desirable for feed to steam cracker 50. Theprocesses disclosed herein have been demonstrated to work at pressuresas low as 20 barg, which is a less severe condition than the conditionstypically employed with a commercial hydrotreating catalyst. Ability tooperate at lower pressures reduces the required pressure rating forprocess vessels (e.g., the hydroprocessing reactor 20) and provides anopportunity for reduced investment costs.

The disclosed embodiments also demonstrate olefins in the hydrocarbonproduct are reduced typically to less than 1 wt % of the treatedhydrocarbon stream 32 from a feed olefin concentration of 20 wt % ormore in the hydrocarbon stream 12.

Thus, the disclosed embodiments achieve the pyrolysis of plastics andalso requirements of chloride content, olefin content, and boiling endpoint of the feed for a steam cracker starting from a plastic pyrolysisfeed.

EXAMPLES

The subject matter having been generally described, the followingexamples are given as particular embodiments of the disclosure and todemonstrate the practice and advantages thereof. It is understood thatthe examples are given by way of illustration and are not intended tolimit the specification of the claims to follow in any manner.

Examples 1 to 9 were conducted in a fixed bed reactor located inside a3-zone split-tube furnace. The reactor internal diameter was 13.8 mm andhad concentrically located bed thermowell of 3 mm outer diameter. Thereactor was 48.6 cm long. Commercial hydroprocessing catalyst of Co—Moon alumina (8 g bone dry weight) was broken along the length toparticles of 1.5 mm long and diluted with SiC in the ratio of 60% SiC to40% catalyst to give a mean particle diameter of 0.34 mm. This was doneto avoid slip through of the chlorides due to wall slip or channeling inthe small diameter reactor. Pre-heating bed and post-catalyst inert bedswas provided in the form of 1 mm glass beads. The catalyst bedtemperature was controlled to isothermal by varying the controlledfurnace zone skin temperatures. The catalyst was sulphided using 3 wt %S in hexadecane (S was introduced as dimethyl disulphide). Liquid feed(i.e., the hydrocarbon stream) was fed through a metering pump and H₂gas was fed using a mass flow controller. The reactor effluent (i.e.,the hydrocarbon product) gases were cooled to condense out the liquids(i.e., the treated hydrocarbon stream in the form of a liquid product)under pressure while allowing non-condensed gases (e.g., containingchloride(s), chlorine, hydrogen sulphide, or combinations thereof) toseparate., Following liquid condensation, the pressure of the liquidswas reduced and effluent gas flow was measured using a drum-type wet gasmeter. The effluent gas flow was analyzed using a refinery gas analyzer(a custom gas analyzer from M/s AC Analyticals BV). The liquid productolefin content was determined using a Detailed Hydrocarbon Analyzer GC(DHA) and a boiling point characterization was obtained using a SIMDISGC. The liquid product chloride content was measured using a ChloraM-series analyzer (monochromatic wavelength dispersive X-rayFluorescence technique, ASTM D7536).

Example 1

In Example 1, a hydrocarbon feed mixture was prepared by mixing 30 wt %n-hexadecane, 10 wt % i-octane, 20 wt % 1-decene, 20 wt % cyclohexane,and 20 wt % ethyl benzene. Dimethyl disulphide, 2-chloropentane,3-chloro-3-methyl pentane, 1-chlorohexane, (2-chloroethyl) benzene, andchlorobenzene were then added to give 205 ppmw organic chlorides and asulphur content of 2 wt % S in the combined feed mixture. This combinedfeed mixture was used as the hydrocarbon stream which was contacted withthe hydroprocessing catalyst in the packed bed reactor as mentionedabove in the presence of H₂ at conditions of 280° C. reactortemperature, 60 barg reactor pressure, 0.92 hr⁻¹ WHSV, and 414 NL/LH₂/HC flow ratio. The liquid product (i.e., the treated hydrocarbonstream) was analyzed in a DHA wherein molecules lighter than C₁₃ areinjected into the GC column and heavier than C₁₃ are flushed out. Thenormalized composition of liquid product as measured by DHA wasparaffins (26.24 wt %), i-paraffins (17.28 wt %), olefins (0 wt %),naphthenes (33.61 wt %), and aromatics (22.88 wt %). SIMDIS analysis ofliquid product indicates that 78 wt % of the liquid product boils at180° C., and immediately at 79 wt %, the boiling point shifts to 286°C.; indicating that 22 wt % (i.e. 100-78=22) of the liquid product ishexadecane. This implies out of 30 wt % hexadecane in the feed(calculated based on the feed excluding chloride and sulphides, sincedimethyl disulphide is converted to gases, the chloride compounds aredechlorinated so as to contribute less than 0.5 wt % of the product), 8wt % of hexadecane was hydrocracked to lower products. As mentionedbefore, this 22 wt % does not get analyzed in DHA. This 22 wt %hexadecane unaccounted in DHA composition is added to the liquid productanalyzed by DHA (DHA composition multiplied by 0.78 fraction that wasinjected into DHA) and the resulting composition of the liquid productis 42.47 wt % paraffins, 13.48 wt % i-paraffins, 0 wt % olefins, 26.21wt % naphthenes and 17.84 wt % aromatics. In addition, the chloridecontent of the liquid product was 0.09 ppmw.

Example 1 demonstrates it is possible to simultaneously dechlorinate,hydrogenate, and hydrocrack a PIONA hydrocarbon stream containing heavyhydrocarbon molecules (e.g., hexadecane), a chloride content of morethan 200 ppm, and an olefin content of 20 wt % (calculated based on thefeed excluding chloride and sulphides) such that a portion of the heavyhydrocarbon molecules are hydrocracked, chloride content is reduced toless than 1 ppm, and olefins are completely removed (0 wt % in theliquid product). Comparing feed and liquid product compositions, it canbe said that paraffins, i-paraffins, and naphthenes have increased inconcentration, while aromatics have reduced in concentration and olefinswere completely depleted. This clearly indicates hydrocracking ofhexadecane as well as hydrocracking of olefins in feed. Thus, Example 1additionally demonstrates olefins are hydrocracked in addition to beinghydrogenated.

The DHA analysis summary by carbon number for the liquid product isshown below:

n- i- Ole- Naph- Aro- Paraffins, Paraffins, fins, thenes, matics, Total,Carbon No. wt % wt % wt % wt % wt % wt % 2 3 4 0.015 0.015 5 0.012 0.0126 0.016 0.18 27.136 0.048 27.217 7 0 8 0.145 14.226 0.547 21.979 36.8969 0.079 5.901 0.834 6.814 10 26.01 2.93 0.039 11 12 Total, wt % 26.22117.268 35.584 22.86 99.933 Unknown 0.053 Heavies 0.013

Example 2

Example 2 explores the effect of operating pressure on hydrocrackingperformance. A hydrocarbon feed mixture was prepared by mixing 30 wt %n-hexadecane, 10 wt % i-octane, 20 wt % 1-decene, 20 wt % cyclohexane,and 20 wt % ethyl benzene. Dimethyl disulphide, 2-chloropentane,3-chloro-3-methyl pentane, 1-chlorohexane, (2-chloroethyl) benzene, andchlorobenzene were then added to give 205 ppmw organic chlorides and asulphur content of 2 wt % S in the combined feed mixture. This combinedfeed mixture was used as a hydrocarbon stream which was contacted thesulphided hydroprocessing catalyst in the packed bed reactor asmentioned above in the presence of H₂ at conditions of 300° C. reactortemperature, 0.92 hr⁻¹ WHSV, and 414 NL/L H₂/HC flow ratio. Threedifferent pressure conditions were studied: 60 barg for Example 2A, 20barg for Example 2B, and 10 barg for Example 2C. The liquid products(i.e., the treated hydrocarbon streams) for each of Examples 2A to 2Cwere analyzed using SIMDIS, and the results are shown below:

Example 2A Example 2B Example 2C Liquid Product Liquid Product LiquidProduct 60 barg 20 barg 10 barg Cut, T, Cut, T, Cut, T, wt % ° C. wt % °C. wt % ° C. 0 61.4 0 52.0 0 61.4 5 72.0 5 61.4 5 72.0 10 72.0 10 72.010 72.0 15 72.0 15 72.0 15 72.0 20 72.0 20 72.0 20 72.0 25 72.0 25 72.025 72.0 30 87.6 30 72.0 30 72.0 35 87.6 35 72.0 35 87.6 40 87.6 40 87.640 87.6 45 87.6 45 87.6 45 132.0 50 87.6 50 134.6 50 137.2 55 129.4 55137.2 55 139.8 60 134.6 60 139.8 60 139.8 65 139.8 65 142.4 65 161.2 70170.6 70 163.2 70 173.8 75 176.0 75 175.4 75 177.0 79 177.6 80 179.0 78178.0 80 278.6 83 180.6 80 271.6 85 289.2 85 279.6 85 288.2 90 292.0 90291.0 90 291.6 95 294.0 95 294.6 95 294.0 99 295.4 99 296.8 99 295.4 100295.6 100 297.0 100 295.6

The DHA analysis summary of the liquid product boiling below 240° C. isshown below:

Example n-Paraffins, i-Paraffins, Olefins, Naphthenes, Aromatics,Unknown, Heavies, No. wt % wt % wt % wt % wt % wt % wt % 2A 22.50719.415 0.183 31.159 17.912 0.131 0.693 2B 19.544 21.513 0.047 30.49027.465 0.315 0.626 2C 21.368 21.281 0.000 24.687 30.719 0.355 1.591

The results provided in the tables above indicate that 20 wt % or lessof the liquid product for each of Examples 2A to 2C boils in thehexadecane boiling point range. In contrast, the feed contained 30 wt %hexadecane (calculated based on the feed excluding chlorides andsulphides). Hence, at all pressures, hydrocracking of heavy hydrocarbonmolecules (e.g., hexadecane) using a hydrogenation catalyst isdemonstrated.

The corresponding chloride contents of the liquid product (i.e., treatedhydrocarbon stream) at 60 barg, 20 barg, and 10 barg were respectively0.11 ppmw, 0.09 ppmw, and 0.12 ppmw.

The liquid product (analyzed in DHA) for Example 2A (60 barg) contained0.183 wt % olefins, for Example 2B (20 barg) contained 0.047 wt %, andfor Example 2C (10 barg) contained 0 wt % olefins. At lower pressures, asignificant increase in aromatics is observed.

Example 2 demonstrates it is possible to simultaneously dechlorinate andhydrocrack a PIONA hydrocarbon stream containing heavy hydrocarbonmolecules (e.g., hexadecane) and a chloride content of more than 200ppmw such that a portion of the heavy hydrocarbon molecules arehydrocracked and chloride content is reduced to less than 1 ppm for allpressures tested.

Example 3

In Example 3, a hydrocarbon feed mixture was prepared to contain 30 wt %n-hexadecane, 10 wt % i-octane, 20 wt % 1-decene, 20 wt % cyclohexaneand 20 wt % ethyl benzene. To this the organic chlorides mentioned inExample 2 above were added along with dimethyl disulphide to give 205ppm organic chlorides and 2 wt % S in the mixture. This feed was used asa hydrocarbon stream which was contacted with the sulphidedhydroprocessing catalyst in the packed bed reactor as mentioned above inthe presence of H₂ at conditions of 260° C. reactor temperature, 60 bargreactor pressure, 0.92 hr⁻¹ WHSV and 414 NL/L H₂/HC flow ratio. Theliquid product (i.e., the treated hydrocarbon stream) contained 0.1 ppmwchloride.

Example 3 demonstrates the effective removal of chloride compounds froma hydrocarbon stream at very low temperatures.

Example 4

In Example 4, a feed was prepared by mixing plastic pyrolysis oil (36.3g) with n-hexadecane (240 g), and then adding dimethyl disulphide (thesulphide) and 1-chlorohexane (the chloride compound) to give a sulphurcontent of 2.34 wt % and 836 ppm chloride in the feed. This feed wasused as a hydrocarbon stream which was contacted with thehydroprocessing catalyst in the packed bed reactor as mentioned above inthe presence of H₂ under several operating conditions as provided in thetable below:

T, P, WHSV, H₂/HC, Cl, ppm in ° C. barg hr⁻¹ NL/L liquid product 300 600.92 414 0.32 300 40 0.92 414 0.87 350 40 0.92 414 3.42 400 40 0.92 4143.15

The gas composition of the reactor effluents is as below and indicatesLPG gases are formed at temperatures close to 400 deg C.:

Cl, ppm in n- i- T, P, WHSV, H₂/HC, liquid H₂, CH₄, C₂H₆, C₃H₈, C₄H₁₀,C₄H₁₀, ° C. barg hr⁻¹ NL/L product mole % mole % mole % mole % mole %mole % 300 40 0.92 414 0.87 96.63 3.25 0.12 — — — 350 40 0.92 414 3.4295.32 4.48 0.2 — — — 400 40 0.92 414 3.15 93.96 5.21 0.45 0.23 0.08 0.07

Example 4 demonstrates it is possible to dechlorinate a hydrocarbonstream containing plastic pyrolysis oil and having chloride compoundsfrom a chloride content of more than 800 ppm chlorides to less than 5ppm in the liquid product. As can be seen from the above table, thechloride content of the liquid product (i.e., the treated hydrocarbonstream) increases when the reactor bed temperature is increased to at orabove 350° C. At temperatures below 350° C., Example 4 demonstratesremoval of chloride compounds to chloride contents less than 3 ppm, andeven sub-ppm levels.

Example 5

In Example 5, a feed was prepared by mixing plastic pyrolysis oil (36.3g) with n-hexadecane (240 g), and then adding dimethyl disulphide (thesulphide) and 1-chlorohexane (the chloride compound) to give a sulphurcontent of 2.34 wt % and 836 ppm chloride in the feed. This feed wasused as a hydrocarbon stream which was contacted with thehydroprocessing catalyst (chlorinated and sulphided Co—Mo on alumina) inthe packed bed reactor as mentioned above in the presence of H₂ underoperating conditions of 40 barg reactor pressure, 400° C. reactor bedtemperature, 0.92 hr⁻¹ WHSV, and a hydrogen to hydrocarbon ratio of 414NL/L. The product from this reactor had 2.94 ppmw chloride. A polishingstep was performed by mixing 5 g of the product with 1 g of gammaalumina (the adsorbent) at room temperature for 1 hr to monitoradsorptive performance. The supernatant from this polishing step wasanalyzed for chloride content, which was found to have 1.46 ppmwchloride. Thus a chloride content from 2.94 ppmw obtained from a nearend-of-run condition for the hydroprocessing catalyst (a border-linevalue for steam cracker feed) was reduced in the polishing step to anacceptable chloride level of 1.46 ppmw.

Example 6

In Example 6, a hydrocarbon feed mixture was prepared to contain 30 wt %n-hexadecane, 10 wt % i-octane, 20 wt % 1-decene, 20 wt % cyclohexane,and 20 wt % ethyl benzene. To this were added dimethyl disulphide,2-chloropentane, 3-chloro-3-methyl pentane, 1-chlorohexane,(2-chloroethyl) benzene and chlorobenzene to give 205 ppm organicchlorides and 2 wt % S in the mixture. A dechlorination step wasperformed by mixing 5 g of this feed mixture with 1 g of gamma aluminaat room temperature for 1 hr to monitor adsorptive performance. Thesupernatant was measured for its chloride content, which was found to be191 ppmw.

Example 6 demonstrates that dechlorination by adsorption for hydrocarbonstreams contemplated in this disclosure as feeding to a firsthydroprocessing reactor does not effectively reduce the chloride contentto levels required for steam crackers. However, Example 6 and Example 5demonstrate adsorption units may be useful in the disclosed polishingzone, alone or upstream or downstream of a second hydroprocessingreactor.

Example 7

In Example 7, a feed was prepared by adding dimethyl disulphide (thesulphide) and 2-chloropentane, 3-chloro-3-methyl pentane,1-chlorohexane, (2-chloroethyl) benzene, and chlorobenzene (the chloridecompounds) to n-hexadecane to give a sulphur content of 2 wt % in themixture and a chloride content of 1,095 ppm in the mixture. Each of thechloride compounds contributed approximately 220 ppm to the feedmixture. This feed was used as a hydrocarbon stream which was contactedwith the hydroprocessing catalyst in the packed bed reactor as mentionedabove in the presence of H₂ at 300° C. reactor bed temperature, 40 bargreactor pressure, 414 NL/L H₂/HC flow ratio, and 0.92 hr⁻¹ weight hourlyspace velocity (WHSV). The chloride content of the liquid product (i.e.,treated hydrocarbon stream) was 0.23 ppmw.

Example 7 demonstrates it is possible to dechlorinate a hydrocarbonstream containing no olefins and chloride compounds from a chloridecontent of about 1,100 ppm chlorides to the sub-ppm level in the in theliquid product.

Example 8

In Example 8, a hydrocarbon feed mixture was prepared by mixing 30 wt %n-hexadecane, 10 wt % i-octane, 20 wt % 1-decene, 20 wt % cyclohexane,and 20 wt % ethyl benzene. Dimethyl disulphide, 2-chloropentane,3-chloro-3-methyl pentane, 1-chlorohexane, (2-chloroethyl) benzene, andchlorobenzene were then added to give 1,100 ppmw organic chlorides and asulphur content of 2 wt % S in the combined feed mixture. This combinedfeed mixture was used as the hydrocarbon stream which was contacted withthe hydrogenating catalyst in the packed bed reactor as mentioned abovein the presence of H₂ at conditions of 300° C. reactor temperature, 40barg reactor pressure, 0.92 hr⁻¹ WHSV, and 414 NL/L H₂/HC flow ratio.The liquid product contained 0.23 ppmw chlorides and paraffins of 22.569wt %, paraffins of 19.752 wt %, olefins of 0.114 wt %, naphthenes of33.242 wt %, aromatics of 23.7 wt %, unknowns of 0.16 wt % and heaviesof 0.463 wt % as per DHA analysis. This again demonstrates thedechlorination of liquid at much higher chloride concentrations.

The SIMDIS of liquid product resulted in the following distribution andalso indicated hydrocracking:

Cut, T, wt % ° C. 0 61.4 5 72 10 72 15 72 20 72 25 72 30 72 35 72 4087.6 45 87.6 50 132 55 134.6 60 137.2 65 142.4 70 170.6 75 175.4 80 17785 287 90 290 95 292.2 99 293.4 100 293.8

DHA Group type analysis of the liquid product by carbon number (in wt %)is as below:

n-Paraffins, i-Paraffins, Olefins, Naphthenes, Aromatics, Total, CarbonNo. wt % wt % wt % wt % wt % wt % 2 0 3 0 4 0.008 0.056 0.064 5 0.0330.021 0.054 6 0.035 0.05 26.925 0.072 27.082 7 0.013 0.008 0.012 0.033 80.287 13.892 0.951 21.97 37.1 9 0.172 0.114 5.265 1.623 7.174 10 22.1615.553 0.089 0.035 27.838 11 0.025 0.025 12 0.007 0.007 OxygenatesHeavies 0.464 Unknown 0.16 Total, wt % 100.001

In this example, the yield of liquid products was 95.5 wt % of the totalproducts. The balance was gas products.

Example 9

In Example 9, a n-hexadecane feed mixture was prepared by mixingn-hexadecane with dimethyl disulphide, 2-chloropentane,3-chloro-3-methyl pentane, 1-chlorohexane, (2-chloroethyl) benzene, andchlorobenzene to give 1,034 ppm of chlorides and 2 wt % Sulphur in thefeed. This combined feed mixture was used as the hydrocarbon streamwhich was contacted with the hydrogenating catalyst in the packed bedreactor as mentioned above in the presence of H₂ at conditions of 300°C. reactor temperature, 40 barg reactor pressure, 0.92 hr⁻¹ WHSV, and414 NL/L H₂/HC flow ratio. The liquid product contained 0.3 ppmwchlorides and paraffins of 22.569 wt %, i-paraffins of 19.752 wt %,olefins of 0.114 wt %, naphthenes of 33.242 wt %, aromatics of 23.7 wt%, unknowns of 0.16 wt % and heavies of 0.463 wt % as per DHA analysis.This again demonstrates the dechlorination of liquid at high chlorideconcentrations to sub-ppm levels.

The SIMDIS of liquid product resulted in the following distribution andalso indicated hydrocracking to the extent of about 15 wt % on achloride and sulphide-free feed basis:

Cut Temp (wt %) (° C.) 0 61.4 5 129.4 10 161.2 13 170.6 14 260.2 15272.4 20 285.2 25 287.4 30 289 35 290.2 40 291.2 45 292.2 50 293 55293.8 60 294.4 65 295 70 295.6 75 296.2 80 297 85 297.4 90 297.8 95298.2 99 298.8 100 310.8

DHA Group type analysis of the liquid product by carbon number (in wt %)is as below and indicates conversion of n-hexadecane to various PIONAcomponents:

n-Paraffins, i-Paraffins, Olefins, Naphthenes, Aromatics, Total, CarbonNo. wt % wt % wt % wt % wt % wt % 2 0.005 0.005 3 0.006 0.006 4 0.0190.098 0.118 5 0.068 0.064 0.132 6 0.072 0.133 25.607 0.11 25.922 7 0.0160.034 0.051 8 0.401 13.31 1.268 21.179 36.157 9 0.133 0.136 5.53 2.4498.248 10 19.165 8.19 0.213 0.049 27.617 11 0.03 0.03 12 0.011 0.011Oxygenates Heavies 1.413 Unknown 0.29 Total, wt % 100

Example 10

Example 10 shows a high severity operation for the pyrolysis unit 10. Anamount of 1.5 g of plastics feed and 9 g of catalyst mixture having acomposition comprised of 37.5 wt. % ZSM-5 catalyst, with the remainderbeing spent FCC catalyst, were used in pyrolysis conversions in afluidized bed reactor. Details regarding the experimental facility forExample 10 are described in U.S. Patent Publication No. 2014/0228606A1,which is incorporated herein by reference in its entirety. The mixedplastics feed had the following composition:

Amount, Material wt % HDPE 19 LDPE 21 PP 24 C₄-LLDPE 12 C₆-LLDPE 6 PS 11PET 7

The reaction temperature at start of reaction was 670° C. The one-minuteaverage bed temperatures achieved was 569.6° C. The Catalyst/Feed (C/F)ratio was 6. Fluidization N₂ gas flow rate used was 175N cc/min. Overallaromatic and liquid i-paraffin product yields and aromatic and liquidi-paraffin content in liquid product boiling below 240° C. were 31.6 wt% and 5.76 wt %, respectively. Their respective concentrations in theliquid product boiling below 240° C. was 74.72 wt % and 13.22 wt %. Theyield of light gas olefins, i.e., the sum of yields of ethylene,propylene and butenes was 32.69 wt %, and the total yield of gasproducts was 45.17 wt %.

The DHA analysis of the liquid product boiling below 240° C. was:

n-Paraffins, i-Paraffins, Olefins, Naphthenes, Aromatics, Total, CarbonNo. wt % wt % wt % wt % wt % wt % 5 0.013 0.02 0.169 0.031 0.233 6 0.1010.219 1.031 0.318 5.28 9.113 7 0.254 1.243 2.267 0.665 17.188 21.618 80.544 2.703 0.354 1.125 30.339 35.066 9 0.22 3.98 0.107 1.44 10.95 16.7010 0.12 2.07 0.217 3.89 6.30 11 0.10 2.53 0.299 1.53 4.39 12 0.05 0.463.37 3.88 13 0.03 0.03 Unknown 2.69 Total, wt % 1.42 13.22 3.928 4.0374.72 97.32 Total, wt % on 6.3 58.5 17.4 17.8 Aromatics- Free Basis

The yield of heavy products boiling above 370° C. was 0.86 wt %.

Example 11

Example 11 shows a high severity operation for the pyrolysis unit 10,operated in a hydrogen-assisted hydropyrolysis mode. An amount of 1.5 gof mixed plastics was mixed with 9 g of a catalyst mixture comprising62.5 wt % spent FCC catalyst and 37.5 wt % ZSM-5 zeolite catalyst. Thecombined mixture was then fed to the fluidized bed reactor described inExample 1. The plastic feed was in the form of a 200 micron plasticpowder. A mixture of 10% H₂ in N₂ was employed as the carrier gas at aflow rate of 175 N cc/min.

Studies were conducted by maintaining the reactor bed temperature,before feed and catalyst mixture was introduced, at 600° C., 635° C.,and 670° C., respectively, i.e., at 3 different starting temperatures.Studies were also conducted at the same conditions as before with 100%N₂ as carrier gas. For each of the temperature conditions studied, a newset of catalyst and feed mixture was prepared and used.

The tables below summarize the experimental findings, where all studyused a mixed plastic feed and spent FCC (62.50 wt %)+ZSM-5 zeolitecatalyst (37.5 wt %) as the pyrolysis catalyst:

Hydro- Hydro- Hydro- pyrolysis 1 Pyrolysis 1 pyrolysis 2 Pyrolysis 2pyrolysis 3 Pyrolysis 3 Feed Weight 1.50 1.50 1.50 1.50 1.50 1.50Transferred, g Bone-Dry Catalyst 9.05 8.95 9.05 9.05 9.01 8.95 Feed, gC/F ratio, g/g 6.03 6.0 6.03 6.03 6.00 6.0 Reaction Start 600 600 635635 670 670 Temperature, ° C. 1 min Avg. Reactor 482 472 525 525 567 570Bed Temperature, ° C. Yield, wt %, based on H₂-free product Methane 0.920.40 1.00 0.56 3.20 0.99 Ethane 0.87 0.43 0.73 0.52 0.69 0.74 Ethylene6.17 3.68 6.50 5.07 6.36 5.78 Carbon Dioxide 1.29 1.63 1.54 1.93 1.851.91 Propane 3.90 4.26 3.15 3.58 3.11 3.49 Propylene 12.76 11.05 13.6312.93 14.67 14.75 i-Butane 4.56 4.99 3.85 4.75 3.77 3.53 n-Butane 2.671.84 2.07 1.57 1.31 1.41 t-2-Butene 3.16 2.67 3.10 2.89 2.99 3.011-Butene 1.75 1.63 1.79 1.79 1.90 2.01 i-Butylene 4.68 4.55 4.56 4.764.72 4.97 c-2-Butene 2.22 1.92 2.19 2.09 2.14 2.21 Carbon Monoxide 1.250.10 0.35 0.00 0.80 0.25 Gasoline 43.83 45.34 41.66 42.42 42.11 49.30Diesel 5.75 9.14 7.55 8.37 4.73 5.16 Heavies 0.56 1.64 0.78 0.88 0.490.86 Coke 4.67 4.73 5.55 5.88 5.12 5.64

Overall, yield of gas products has increased and liquid products havedecreased indicating higher conversions to lighter products.

Hydro- Hydro- Hydro- pyrolysis 1 Pyrolysis 1 pyrolysis 2 Pyrolysis 2pyrolysis 3 Pyrolysis 3 C₁-C₄ Yield, wt % 45.2 39.1 44.5 42.5 47.5 45.0Liquid Yield, wt % 50.1 56.1 50.0 51.7 47.3 49.3 Coke Yield, wt % 4.74.7 5.6 5.9 5.1 5.6

As can be seen, the yield of light gas olefins per unit amount of cokedeposited on the catalyst is higher in the case of hydropyrolysis. Thisimplies that more light gas olefins would be produced in a circulatingfluid catalytic cracking type of unit. In these units, performance iscompared on a constant coke yield basis. This is because the amount ofcoke burnt off in the regenerator is limited by the air availability inthe regenerator and as a result the regenerated catalyst returned backto the riser would have more or less coke on it which would in turnaffect its activity in the riser.

The total aromatics as well as C₆-C₈ aromatics yield per unit amount ofcoke deposited is also higher in the case of hydropyrolysis. Thisimplies in hydropyrolysis more aromatic products would be produced in acirculating fluid catalytic cracking type of unit.

Hydro- Hydro- Hydro- pyrolysis 1 Pyrolysis 1 pyrolysis 2 Pyrolysis 2pyrolysis 3 Pyrolysis 3 Total Aromatics 32.42 31.39 32.81 31.83 35.0932.35 Yield Boiling Below 240° C., wt % C₆-C₈ Aromatics 23.81 23.2024.44 22.63 26.33 22.87 Yield, wt % Total 6.9 6.6 5.9 5.4 6.9 5.7Aromatics/Coke, wt ratio (C₆-C₈ 5.1 4.9 4.4 3.9 5.1 4.1 Aromatics)/Coke,wt ratio Light gas 6.6 5.4 5.7 5.0 6.4 5.8 olefins/Coke, wt ratio C₄Olefins, wt % 11.81 10.76 11.64 11.54 11.77 12.20 C₃ Olefins, wt % 12.7611.05 13.63 12.93 14.67 14.75 C₂ Olefins, wt % 6.17 3.68 6.50 5.07 6.365.78 Total Olefins, wt % 30.74 25.49 31.77 29.54 32.80 32.72

To summarize, more high value chemicals (i.e. light gas olefins andaromatics) are produced in hydropyrolysis as compared to pyrolysis donewithout use of hydrogen carrier gas.

Additional benefits include:

-   -   a. increased olefinicity of product gases;    -   b. increased ratio of propylene/propane as compared to ethylene        to ethane and butenes/butanes;    -   c. lower hydrogen transfer index (i.e. ratio of C₃ and C₄        saturates/C₃ olefins) in hydropyrolysis as compared to use of        nitrogen only as carrier gas; and    -   d. more C₄ iso-olefins are produced in as compared to 1-butene        in hydropyrolysis (i.e. isomerization index is lower).

Hydro- Hydro- Hydro- pyrolysis 1 Pyrolysis 1 pyrolysis 2 Pyrolysis 2pyrolysis 3 Pyrolysis 3 Hydrogen Transfer 0.87 1.00 0.67 0.77 0.56 0.57Index (HTI) Isomerization 0.174 0.178 0.182 0.184 0.192 0.197Coefficient C₂ Olefin/C₂ Saturated 7.1 8.6 8.9 9.8 9.2 7.9 HydrocarbonC₃ Olefin/C₃ Saturated 3.3 2.6 4.3 3.6 4.7 4.2 Hydrocarbon C₄ Olefin/C₄Saturated 1.6 1.6 2.0 1.8 2.3 2.5 Hydrocarbon % of i-C₄/Total C₄ 23.928.4 21.9 26.6 22.4 20.6 % of Olefins/Total 68.0 65.1 71.5 69.6 69.072.6 Gases % Olefins/% 2.6 2.2 3.2 2.8 3.7 3.6 Saturated Hydrocarbons

Detailed hydrocarbon analysis (DHA) of liquid products below 240° C. isin the table below:

Hydro- Hydro- Hydro- pyrolysis 1 Pyrolysis 1 pyrolysis 2 Pyrolysis 2pyrolysis 3 Pyrolysis 3 Paraffins, wt % 1.184 1.435 1.207 1.170 1.1081.420 i-Paraffins, wt % 10.161 12.389 9.598 12.120 8.545 13.330 Olefins,wt % 2.944 9.159 2.555 4.858 0.976 3.900 Naphthenes, wt % 3.727 5.3903.135 3.867 2.329 4.030 Aromatics, wt % 73.968 69.233 78.758 75.03783.315 74.720 BTX + EX content in 54.32 51.17 58.67 53.35 62.52 52.81liquid boiling below 240° C.

Example 12

Example 12 shows a low severity pyrolysis operation. The experimentalset up consisted of a stainless steel reactor pot followed by a fixedbed (tubular) reactor packed with ZSM-5 zeolite extrudates and theoutlet of this tubular reactor was connected to a stainless steelcondenser/receiver tank. The reactor pot was heated using heating tapeswith temperature controller. An amount of 100 g of mixed plastic as percomposition provided in Example 10 was charged along with ZSM-5 zeolitecatalyst powder of 75 microns average particle size into the reactor andthe heating was started. The reactor temperature was maintained constantat 450° C. for a period of 1 hr. The effluent from this reactor pot wascontinuously passed through the hot tubular reactor packed with ZSM-5extrudates and maintained at 450° C. The product from the tubularreactor was sent to the receiver. The outgoing gas from the receiver waspassed through NaOH scrubber and then diluted with N₂ and vented outthrough a carbon bed. Two different catalyst loadings were tested asbelow:

-   -   a. Experiment 1: Equivalent to 5 wt % of the feed was the        catalyst charged in the tubular reactor and 5 wt % equivalent        catalyst was charged in the reactor pot (i.e. 10 wt % of        catalyst overall).    -   b. Experiment 2: Equivalent to 5 wt % of the feed was the        catalyst charged in the tubular reactor and 15 wt % equivalent        catalyst was charged in the reactor pot (i.e. 20 wt % catalyst        overall).

FIG. 2 shows the boiling point distribution of the liquid productobtained indicated that 95 wt % of the liquid product boiled below 370°C.

The DHA analysis of the liquid product boiling below 240° C. indicatedsignificant presence of olefins and aromatics:

Liquid Product boiling Liquid Product boiling Product below 240° C. frombelow 240° C. from Composition Experiment 1, wt % Experiment 2, wt %Paraffins 6.5 3.1 i-Paraffins 17.6 11.7 Olefins 11.4 7.4 Naphthenes 3.82.5 Aromatics 47.9 66.3 Heavies 3.1 3.6 Unknown 9.8 5.5

Example 13

Example 13 demonstrates a low severity pyrolysis with PVC present in thefeed. An amount of 100 g of mixed plastic feed as per the compositionprovided in Example 10 above was mixed with 2 wt % of ZSM-5 zeolitecatalyst powder and heated in a round bottom flask fitted with acondenser. The round bottom flask was maintained at 360° C. for 1 hour.The liquid product had 60 ppmw chlorides. A similar experiment conductedwith head space purging of the round bottom flask with N₂ gas provided aliquid product with no detectable chloride content. Chloride content inthe liquid products was determined by fusing liquid products in NaOHfollowed by extraction in water and measurement of the resultant aqueoussolution chloride content using ion chromatography. This example alsodemonstrates the possibility of head space purging in a pyrolysis unitto enhance dechlorination.

Example 14

Example 14 demonstrates a low severity pyrolysis process in a fluidizedbed. An amount of 1.5 g of mixed plastic feed as per compositionprovided in Example 10 was mixed with 9.05 g of a catalyst mixturecontaining 62.5 wt % of FCC spent catalyst and 37.5 wt % of ZSM-5Zeolite catalyst. This combined mixture was charged into the fluidizedbed reactor described in Example 10. Before charging of feed andcatalyst mixture the reactor was at a temperature of 450° C. The reactortemperature decreased as the feed was charged and later increased to theset point of 450° C. Data provided below also captures the temperatureprofile in the reactor bed as a function of time. The 1 min, 6 min, and10 min average bed temperatures were 333° C., 369° C., and 395° C.,respectively. The 1 min average represents the average reactiontemperature severity when most temperature changes occur in the reactor.The 6 min average represents the temperature severity when the reactortemperature has recovered and reached the previously set value. Most ofthe conversion in the low severity case was expected to have beencompleted at the 6 min average. The data below shows that the liquidproduct is highly aromatic, the heavier than 370° C. boiling material isonly about 2 wt %, and more than 90 wt % of the liquid product boilsbelow 350° C.

The product yield data is shown in the table below:

Amount, wt % H₂ 0.03 Methane 0.00 Ethane 0.00 Ethylene 2.25 CarbonDioxide 1.54 Propane 3.39 Propylene 6.92 i-Butane 6.48 n-Butane 1.67t-2-Butene 1.71 1-Butene 1.04 i-Butylene 3.37 c-2-Butene 1.26 CarbonMonoxide 0.00 Gasoline 45.28 Diesel 17.64 Heavies 2.08 Coke 5.33

The boiling point distribution is in the table below:

Mass Boiling Point, % ° C. 0.0 108.6 5.0 156.0 10.0 164.0 15.0 175.620.0 180.0 25.0 187.6 30.0 190.2 35.0 198.8 40.0 203.6 45.0 209.2 50.0220.2 55.0 227.0 60.0 232.0 65.0 246.0 70.0 254.2 75.0 267.4 80.0 281.885.0 300.6 90.0 332.0 95.0 371.6 99.0 431.2 100.0 454.2

The detailed analysis of the liquid product is shown in the tablebelow:\

n-Paraffins, i-Paraffins, Olefins, Naphthenes, Aromatics, Total, CarbonNo. wt % wt % wt % wt % wt % wt % 3 0.003 0.003 4 0.007 0.012 0.041 0.065 0.032 0.077 0.325 0.095 0.529 6 0.173 0.566 1.025 1.009 4.757 7.53 70.379 1.379 1.547 2.095 19.393 24.793 8 0.398 2.443 0.198 1.518 28.46633.023 9 0.046 1.911 0.134 0.958 11.254 14.303 10 0.019 0.916 0.02 0.1564.448 5.559 11 0.022 2.114 0.029 1.621 3.786 12 0.029 0.199 0.057 3.8844.169 13 0.078 0.111 0.189 Unknown 2.842 Heavies 3.214 Total, wt % 1.1059.695 3.404 5.917 78.823 93.944 Total, wt % 5.49 48.18 16.92 29.41 onAromatics- Free Basis

Example 15

Example 15 demonstrates how a steam cracker is used in combination withpyrolysis and hydroprocessing unit. Gases (C₁-C₄) from a pyrolysis unitand hydroprocessing facility are fed to gas crackers. Liquids from thehydroprocessing facility are fed to liquid steam crackers.

Gas steam cracking of a feed consisting of 16.75 w % ethane, 34.62 wt %propane, 27.62 wt % isobutene and 21 wt % butane, carried out at a steamcracker coil outlet temperature of 840° C., a steam/hydrocarbon ratio of0.35, and a coil outlet pressure of 1.7 bar, resulted in a producthaving 0.48 wt % acetylene, 34.1 wt % ethylene, 12.21 wt % propylene,and 2.41 wt % butadiene, among other products.

Steam cracking a naphtha feed (boiling cut from initial boiling point to220° C.) having 20.3 wt % paraffin, 27.9 wt % i-paraffins, 14.5 wt %aromatics, and 36.9 wt % naphthenes at a coil outlet temperature of 865°C., a coil outlet pressure of 1.7 bar, and a steam to oil ratio of 0.5resulted in a product having 25.86 wt % ethylene, 12.14 wt % propylene,and 4.98 wt % butadiene.

Steam cracking of gas oils (>220° C. boiling point to 380° C.) resultedin a product having 24 wt % ethylene, 14.45 wt % propylene, 4.7 wt %butadiene, and 4.5 wt % butenes.

Example 16

Example 16 demonstrates a process for sulphiding a hydroprocessingcatalyst. The particular steps of the process are shown in FIG. 3. Thetime of 0 hours (zero time) in FIG. 3 corresponds to a time after thehydroprocessing catalyst is introduced into the hydroprocessing reactor.

At ambient temperature, the hydroprocessing reactor (having previouslybeen loaded with the hydroprocessing catalyst) was purged with hydrogenfor 30 to 60 minutes at a set operating pressure (e.g., 40 to 60 barg).The set operating pressure was maintained by venting the reactor whenthe pressure of the reactor during hydrogen purging increased above theset operating pressure (e.g., due to a hydrogen source pressure greaterthan the set operating pressure).

After purging the hydroprocessing reactor for 30 to 60 minutes atambient temperature, the hydrogen purge was stopped.

Still at the ambient temperature, the sulphiding feed was thenintroduced into the reactor using a high pressure pump against the setreactor pressure at a weight hourly space velocity (WHSV) of 3 hr⁻¹ (onbone-dry catalyst basis). The sulphiding feed (e.g., for use in spikingstream 14 of FIG. 1) was prepared by mixing n-hexadecane with dimethyldisulphide in appropriate quantity to give 3 wt % sulphur based on totalweight of the sulphiding feed. For the sulphiding feed, as per catalystsulphiding protocol followed, cracked feedstock cannot be used. Hence,n-hexadecane is used. In place of n-hexadecane, straight-run naphtha,diesel, or vacuum gas oils can also be used.

FIG. 3 indicates the hydroprocessing catalyst was soaked with asulphiding feed without a flow of hydrogen in the reactor and at ambienttemperature for a period of 3 hours (ending at time 3.5 hours after zerotime in FIG. 3). Catalyst soaking provides for complete wetting of thehydroprocessing catalyst; however, soaking is optional. Liquid wasdrained from the bottom of a downstream gas liquid separator.

After introducing the sulphiding feed to the reactor, thehydroprocessing reactor bed temperature was raised to 250° C. at a rateof 30° C. per hour with a flow of H₂ at a ratio of 200NL H₂/L liquidfeed. As shown in FIG. 3, the temperature was increased from a time of3.5 hours to a time of 10.8 hours after zero time.

The hydroprocessing reactor bed temperature was then held at 250° C. fora period of 8 hours. As shown in FIG. 3, the temperature was held from atime of 10.8 hours to a time of 18.8 hours after zero time.

After holding the bed temperature, the bed temperature was furtherincreased to 320° C. to 350° C. at a rate of 20° C. per hour without anytemperature overshoot at the final temperature. As shown in FIG. 3, thetemperature was increased from a time of 18.8 hours to a time of 22.3hours after zero time.

The hydroprocessing reactor bed temperature was then maintained at 320°C. to 350° C. for a period of 8 hours. As shown in FIG. 3, thetemperature was maintained at 320° C. to 350° C. from a time of 22.3hours to a time of 30.0 hours after zero time.

During the step of maintaining the temperature at 320° C. to 350° C. for8 hours, after 5 hours of maintaining the temperature at 320° C. to 350°C., gas sampling began, and a first gas sample was obtained from thereactor effluent. A second gas sample was obtained close to 8 hourswhile the bed temperature is maintained at 320° C. to 350° C. The firstand second gas samples were analyzed in a refinery gas analyzer (RGA)gas chromatograph and constancy of H₂S concentration in reactor effluentgases in the first and second samples signified further uptake ofsulphur on the catalyst did not take place. This marked the completionof the catalyst sulphiding process. If the first and second samples hadnot exhibited constancy in H₂S concentration, additional samples wouldhave been taken and the temperature maintained until two successivesamples exhibited constancy in H₂S concentration.

What is claimed is:
 1. A process for converting waste plastics to a highvalue product comprising: converting the waste plastics to a hydrocarbonstream in a liquid phase, wherein the hydrocarbon stream comprises oneor more chloride compounds in a concentration of 5 ppm or more based ona total weight of the hydrocarbon stream; contacting the hydrocarbonstream with a first hydroprocessing catalyst in the presence of hydrogento yield a first hydrocarbon product comprising C₁ to C₄ gases and C₅+liquid hydrocarbons; recovering the C₅+ liquid hydrocarbons in a treatedhydrocarbon stream from the first hydrocarbon product, wherein thetreated hydrocarbon stream comprises the one or more chloride compoundsin a concentration of 3 to 5 ppm based on a total weight of the treatedhydrocarbon stream; dechlorinating the treated hydrocarbon stream toyield a polished hydrocarbon stream comprising one or more chloridecompounds in a concentration of less than 3 ppm based on a total weightof the polished hydrocarbon stream; and feeding the treated hydrocarbonstream or polished hydrocarbon stream to a steam cracker to yield thehigh value product, wherein the treated hydrocarbon stream or polishedhydrocarbon stream meets steam cracker feed requirements for chloridecontent, olefin content, and boiling end point.
 2. The process of claim1, wherein the step of dechlorinating comprises contacting the treatedhydrocarbon stream with a second hydroprocessing catalyst in thepresence of hydrogen to yield a second hydrocarbon product.
 3. Theprocess of claim 1, wherein the step of dechlorinating comprisesremoving at least a portion of the one or more chloride compounds viaadsorptive dechlorination to yield the polished hydrocarbon stream. 4.The process of claim 1, wherein the polished hydrocarbon streamcomprises the one or more chloride compounds in a concentration of lessthan 1 ppm based on the total weight of the polished hydrocarbon stream,wherein the hydrocarbon stream comprises the one or more chloridecompounds in a concentration of greater than 200 ppmw based on a totalweight of the hydrocarbon stream.
 5. The process of claim 1, wherein thehydrocarbon stream comprises one or more olefins, wherein the treatedhydrocarbon stream comprises the one or more olefins in a concentrationof less than 1 wt. % based on the total weight of the treatedhydrocarbon stream, and wherein the one or more olefins are present inthe hydrocarbon stream in a concentration of 20 wt % or more based onthe total weight of the hydrocarbon stream.
 6. The process of claim 1,wherein the hydrocarbon stream comprises heavy hydrocarbon molecules,and further comprising: hydrocracking at least a portion of the heavyhydrocarbon molecules during the step of contacting the hydrocarbonstream with a first hydroprocessing catalyst.
 7. The process of claim 1,further comprising: before the step of contacting the hydrocarbon streamwith a first hydroprocessing catalyst, contacting a catalyst activatingstream comprising one or more sulphides with the first hydroprocessingcatalyst, and wherein the one or more sulphides are in an amount ofabout 0.5 wt % to 5 wt % based on the total weight of the catalystactivating stream.
 8. The process of claim 1, wherein the one or moresulphides of the hydrocarbon stream are present in a concentration ofabout 2 wt % based on the total weight of the hydrocarbon stream.
 9. Theprocess of claim 1, wherein the step of contacting the hydrocarbonstream with a first hydroprocessing catalyst is performed at a weighthourly space velocity of 0.1 to 10 hr⁻¹, at a hydrogen to hydrocarbonratio of 10 to 3,000 NL/L, and at a pressure of 1 to 200 barg.
 10. Theprocess of claim 1, wherein the first hydroprocessing catalyst comprisescobalt and molybdenum on an alumina support, nickel and molybdenum on analumina support, tungsten and molybdenum on an alumina support, nickelsulphide, molybdenum sulphides, a combination of nickel and molybdenumsulphides, or combinations thereof.
 11. The process of claim 10, whereincontacting the hydrocarbon stream with the first hydroprocessingcatalyst comprises: contacting one or more sulphides contained in oradded to the hydrocarbon stream with the first hydroprocessing catalyst.12. The process of claim 2, wherein the second hydroprocessing catalystcomprises cobalt and molybdenum on an alumina support, nickel andmolybdenum on an alumina support, tungsten and molybdenum on an aluminasupport, nickel sulphide, molybdenum sulphides, a combination of nickeland molybdenum sulphides, or combinations thereof.
 13. The process ofclaim 12, wherein contacting the treated hydrocarbon stream with thesecond hydroprocessing catalyst comprises: contacting one or morechloride compounds contained in the treated hydrocarbon stream with thesecond hydroprocessing catalyst.
 14. The process of claim 1, wherein thehigh value products are ethylene, propylene, butene, butadiene, aromaticcompounds, or combinations thereof.
 15. The process of claim 1, whereinthe step of converting comprises: subjecting the waste plastics to apyrolysis process to produce one or more of plastic pyrolysis oil andtire pyrolysis oil in the hydrocarbon stream.
 16. The process of claim1, wherein recovering a treated hydrocarbon stream from the firsthydrocarbon product comprises: separating the first hydrocarbon productinto a treated product from a first chlorine-containing gas in a firstseparator; and flowing the treated product in the treated hydrocarbonstream from the first separator to an adsorption unit or to a steamcracker.
 17. The process of claim 2, wherein the step of dechlorinatingfurther comprises: separating the second hydrocarbon product into apolished product and a second chlorine-containing gas in a secondseparator; and flowing the polished product in the polished hydrocarbonstream from the second separator to a steam cracker.
 18. The process ofclaim 1, wherein the step of converting the waste plastics to ahydrocarbon stream in a liquid phase is performed in the presence of ahead space purge gas fed to a pyrolysis unit, wherein the head spacepurge gas comprises hydrogen, nitrogen, steam, product gases, orcombinations thereof.
 19. The process of claim 1, further comprising:converting the waste plastics to C₁ to C₄ pyrolysis gases, wherein oneor more of the C₁ to C₄ pyrolysis gases, the C₁ to C₄ gases yielded inthe step of contacting, and C₁ to C₄ gases yielded in the step ofdechlorinating is fed to the steam cracker.
 20. The process of claim 1,wherein the step of contacting includes simultaneous i) dechlorinationof the hydrocarbon stream such that the treated hydrocarbon streamcomprises one or more chloride compounds in a concentration less than 1ppmw based on the total weight of the treated hydrocarbon stream, ii)hydrogenation of the hydrocarbon stream such that the treatedhydrocarbon stream comprises one or more olefins in a concentration lessthan 1 wt % based on the total weight of the treated hydrocarbon stream,and iii) reduction of heavy hydrocarbon molecules of the hydrocarbonstream.